RAAM Global Energy Co - FORM 10-K

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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, 2014

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

FOR THE TRANSITION PERIOD FROM TO .

Commission File No. 333-172897

RAAM Global Energy Company

(Exact name of registrant as specified in its charter)


Delaware		20-0412973
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		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, 2014, 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 27, 2015, 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		28
Item 1B. Unresolved Staff Comments		43
Item 2. Properties		43
Item 3. Legal Proceedings		43
Item 4. Mine Safety Disclosures		44

Part II.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
Item 6. Selected Financial Data		46
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		47
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		105
Item 11. Executive Compensation		107
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		117
Item 13. Certain Relationships and Related Transactions, and Director Independence		118
Item 14. Principal Accounting Fees and Services		121

Part IV.
Item 15. Exhibits and Financial Statement Schedules		122

SIGNATURES		123
Glossary of Oil and Natural Gas Terms		124

INDEX TO EXHIBITS		129

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 in Part I, Item 1A,“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;

•

cash flow and liquidity;

•

our ability to continue as a going concern;

•

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;

•

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 mainly located offshore in the Gulf of Mexico and onshore in Louisiana, Texas 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 goal has been to 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. In 2014, our projects were 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. During 2015, our plan is to concentrate on drilling our shallow water prospects in and around our Gulf of Mexico production in order to increase our proved reserves and cash flows. We are actively working with investment banking advisors to refinance our debt. In conjunction with these advisors, the Company has developed and is executing a robust drilling program.

At December 31, 2014, we had estimated total proved oil and natural gas reserves of 8,898 MMBoe (32% oil). For the year ended December 31, 2014, our net daily production averaged 7,660 Boepd, which generated revenue of $143.1 million.

Core Properties

Our core properties include assets offshore in the Gulf of Mexico in Louisiana state waters and in United States federal waters and onshore conventional assets in Texas and Louisiana. Other areas of concentration include 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 13 producing wells from 10 platforms which we own. Average net daily production for the year ended December 31, 2014 was 2,464 Boepd. During 2014, we made a new discovery in the Louisiana state waters in the East Cox Bay field. Our leasehold position encompassed 14,916 net acres with proved reserves of 3,079 MBoe at December 31, 2014. We have had a 76% drilling success rate in the Breton Sound 53 Field. During 2014, as part of a joint venture agreement, we drilled two dry wells and one successful well. We also drilled our initial well in the East Cox Bay Field, which was successful and was in the process of being placed on line at year end. In Breton Sound, our 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 13 wells and 11 production platforms. During 2014 we drilled one successful well in the Ship Shoal 154 Field which did not come on line by year end. Average net daily production for the year ended December 31, 2014 from the United States federal waters was 701 Boepd. Our leasehold position encompassed 22,727 net acres with proved reserves of 1,029 MBoe as of December 31, 2014.

Onshore

Gulf Coast. We currently operate 20 producing wells onshore along the Gulf Coast in Louisiana and Texas. Average net daily production for the year ended December 31, 2014 was 4,374 Boepd. Our leasehold position encompassed 7,839 net acres with proved reserves of 4,623 MBoe at December 31, 2014. 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, 2014 was 4,237 Boepd from 17 producing wells. During 2014, we drilled and placed into production two wells in the Texas Yegua field. In Louisiana, we have focused on the Lower Miocene Atchafalaya Basin. Average net daily production for the year ended December 31, 2014 was 62 Boepd from 2 producing wells. In addition, we realized 75 Boepd of production for the year ended December 31, 2014 from one well in another area of Louisiana.

Other Resource Plays

Mid-Continent. Our leasehold position in the Mid-Continent area includes 2,176 net acres in Oklahoma, with average net daily production for the year ended December 31, 2014 of 19 Boepd from 8 producing wells. Our leasehold position in the Mid-Continent area also includes 229 net acres in the Tucumcari Basin in New Mexico and approximately 116,000 net acres in a new area which we leased during late 2013.

California. Our leasehold position in the San Joaquin Basin in California encompassed approximately 25,146 net acres with proved reserves of 167 MBoe at December 31, 2014 and average net daily production for the year ended December 31, 2014 of 102 Boepd from 4 producing wells. During 2014, we drilled two additional wells, one successful exploratory oil well and another exploratory oil well which was lost during completion due to mechanical problems.

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, 2014 by reserve category and region. Netherland, Sewell & Associates, Inc., our independent petroleum engineers (“Independent Engineers”), evaluated properties representing all of our proved reserves. Our estimated proved reserves at December 31, 2014 were determined using the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January 2014 through December 2014, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices were $91.48 per Bbl for crude oil and oil equivalents and $4.35 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 $96.85 per Bbl for crude oil and oil equivalents and $5.05 per MMBtu of gas.


	December 31, 2014
	Crude Oil		Natural Gas
	(MBbls)		(MMcf)
Estimated proved developed producing		1,812		28,902
Estimated proved developed non-producing		1,020		7,496
Total estimated proved reserves		2,832		36,398


	Proved Developed
	Crude Oil		Natural Gas
	(MBbls)		(MMcf)
Offshore
Federal waters		870		954
Shallow state waters		1,199		11,280
Onshore
Texas and Louisiana		604		24,114
Resource Plays
Mid-Continent		—		—
California		159		50
Total		2,832		36,398

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


	December 31,
*In MBoe*	2014			2013			2012
Proved reserves beginning of year		10,725			25,044			23,459
Revisions of previous estimates		(1,555	)		(13,337	)		1,249
Extensions, discoveries and other additions		1,993			3,268			4,508
Production		(2,796	)		(3,362	)		(4,172	)
Sales of reserves in place		—			(888	)		—
Purchases of reserves in place		531			—			—
Proved reserves end of year		8,898			10,725			25,044

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. As of December 31, 2014, we had downward revisions of 1,555 MBoe. These revisions included the elimination of previously booked proved undeveloped reserves as of December 31, 2013 of 934 MBoe from our fields in Breton Sound and Ship Shoal. In addition, we lost a previously producing well in the Texas Yegua field due to a formation collapse in third quarter 2014 with estimated proved reserves of 382 MBoe, which requires the drilling of a new well. Other downward revisions of 186 MBoe included write downs of proved developed nonproducing reserves of 186 MBoe in the Breton Sound, Ship Shoal and California fields. All of these revisions, which total 1,502 MBoe, were recorded due to our current debt position causing us to be unable to demonstrate an ability to develop these reserves. The remaining revisions of 53 Mboe were due to normal revisions based on the performance of our producing wells. 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.

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 2014, we had extensions and discoveries of 1,993 MBoe mainly due to a new field discovery in East Cox Bay in the Louisiana state waters and also due to the drilling of an additional well in the Texas Yegua Trend.

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.

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 and the new field discovery in East Cox Bay.

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., 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 2014, we used the services of Netherland, Sewell & Associates, Inc. as our independent petroleum engineering firm. 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 all of our proved reserve information as of December 31, 2014 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 provided to 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 31 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 33 years of practical experience in petroleum engineering, with over 26 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 27 years of practical experience in petroleum geosciences, with over 19 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.

Proved undeveloped reserves. The Company did not book any proved undeveloped reserves at December 31, 2014 due to our current debt position causing us to be unable to demonstrate an ability to develop these reserves. Previously booked proved undeveloped reserves at December 31, 2013 of 934 MBoe were included as revisions to previous estimates. The remaining proved undeveloped reserves of 1,584 MBoe at December 31, 2013 were drilled and completed during 2014 and are included in the Company’s proved developed producing reserves at December 31, 2014.

Capital Expenditure Budget

We have a total capital expenditure budget of $62 million for 2015. During 2014, we invested $111 million on capital expenditures. 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.

Although we have budgeted $62 million for 2015, the ultimate amount of capital we will expend may fluctuate materially based on our ability to refinance our debt, market conditions and the success of our drilling results as the year progresses. To date, our 2015 capital budget has been funded from our cash flows from operations and existing cash balances.

We currently expect that $62 million of our 2015 capital budget will be funded from our cash flow from operations in fiscal 2015, including projected cash flow from new wells, and existing cash balances. We have pre-funded $13.8 million of plugging and abandonment costs for work expected to be performed during 2015. This balance is in an escrow account and is recorded as restricted cash. We expect to add another $7 million incrementally during 2015 to fund required plugging and abandonment projects.

Our 2015 capital budget consists of:

•

$10 million for geological and geophysical costs, including leasing;

•

$4 million for offshore Gulf of Mexico drilling and development;

•

$42 million for offshore State waters drilling and development;

•

$1 million for onshore conventional drilling and development; and

•

$5 million for California drilling and development.

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, 2014:


	Developed acres				Undeveloped acres				Total
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters⁽¹⁾		18,203		17,727		5,000		5,000		23,203		22,727
State waters⁽²⁾		9,780		7,767		7,685		7,149		17,465		14,916
Onshore
Texas and Louisiana⁽³⁾		5,367		4,414		10,061		3,425		15,428		7,839
Resource Plays
California		952		952		30,239		24,194		31,191		25,146
Mid-Continent		5,440		2,176		128,153		116,287		133,593		118,463
Total		39,742		33,036		181,138		156,055		220,880		189,091

(1)	Our core areas 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 areas in the state waters in the Gulf of Mexico are in the Breton Sound 53 Field and the East Cox Bay Field.

(3)	Our core areas 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, 2014 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:


	2015				2016				2017
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters		5,000		5,000		—		—		—		—
State waters		2,349		2,349		—		—		398		398
Onshore
Texas and Louisiana		1,277		1,153		2,538		1,558		4,455		3,639

Resource Plays
California		10,643		8,504		5,059		4,192		8,458		8,002
Mid-Continent		715		118		10,113		9,627		2,240		1,946
Total		19,984		17,124		17,710		15,377		15,551		13,985

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 17,124 net acres expiring in 2015, the majority of this acreage is not in our core areas and we are in the process of extending 135 net acres expiring in the Texas and Louisiana Onshore area for an additional three year term. As of March 16, 2015, we have extended the majority of the leases making up these 135 net acres. We have no reason to believe we will not be able to extend the remaining leases. Our current plan in the other areas is to relinquish control of the leased acreage scheduled to expire in 2015.

Drilling Activity

During the three years ended December 31, 2014, we drilled exploratory and development wells as set forth in the table below:


	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells
Oil		1.0		1.0		—		—		6.0		2.3
Natural Gas		2.0		1.3		—		—		4.0		2.2
Dry		3.0		1.5		1.0		0.7		2.0		1.7
Total Exploratory Wells		6.0		3.8		1.0		0.7		12.0		6.2
Development Wells
Oil		1.0		1.0		1.0		1.0		15.0		6.1
Natural Gas		2.0		1.7		6.0		4.0		4.0		2.8
Dry		—		—		—		—		—		—
Total Development Wells		3.0		2.7		7.0		5.0		19.0		8.9
Total Wells		9.0		6.5		8.0		5.7		31.0		15.1

Our rig activity during 2015 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 2015, we have one rig drilling in the shallow waters of the Gulf of Mexico.

Summary of Oil and Natural Gas Properties and Projects Offshore

We operated 21 offshore production platforms with 26 producing wells as of December 31, 2014. Production from our offshore assets averaged 3,165 Boepd for the year ended December 31, 2014. Our offshore staff includes explorationists who generate prospects from our extensive, modern 3-D seismic database. Our offshore operations cover four 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, (3) the Breton Sound production area in shallow state waters, and (4) the East Cox Bay Field in shallow state waters. In the first three of these core areas, we have platforms, production facilities, and pipelines in place, where production from new wells can be established quickly. In the East Cox Bay Field we have temporary production facilities in place with permanent facilities in process.

In both the Breton Sound and East Cox Bay fields, we have a significant inventory of drilling prospects. In the United States federal waters, we hold 17,727 net acres by production and we have 5,000 net acres that remain undrilled in primary term contracts. In the state waters of Louisiana, we hold 7,767 net acres by production and we have 7,149 net acres that remain undrilled.

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 3% of our average daily production for the year ended December 31, 2014.

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 18 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. During 2014, we drilled one developmental well in this area which was not on line at year end. The Ship Shoal 154 Field represented 7% of our average daily production for the year ended December 31, 2014.

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 11,351 net acres under lease and operate ten production platforms in the Breton Sound 53 Field. The Breton Sound 53 Field represented 32% of our average daily production for the year ended December 31, 2014. During 2014, as part of a joint venture agreement, we drilled two dry wells and one successful well. Our successful well came on line in September 2014 and has produced approximately 481 Boepd since.

East Cox Bay Field. The East Cox Bay Field consists of 3,565 net acres. During 2014 we drilled our initial well in the field which was successful and tested at flow rates of 422 Bopd and 795 Mcfpd. The well began producing in early February 2015 at a rate of 360 Bopd and 450 Mcfpd. The well’s production is currently restricted until the gas pipeline is installed.

Onshore

Production from our onshore properties in the Gulf Coast averaged 4,374 Boepd for the year ended December 31, 2014.

Eocene Yegua/Cook Mountain. During 2014, 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 4,237 Boepd for the year ended December 31, 2014. The Eocene Yegua/Cook Mountain trend represented 55% of our average daily production for the year ended December 31, 2014. We drilled and completed two successful wells in this area during 2014. Our first successful well came on line during February 2014 and has average production of 1,031 Boepd. Our second successful well came on line in November 2014 and has average production of 453 Boepd.

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). During 2014 we continued to focus on conventional and unconventional plays. We have acquired 3-D and 2-D seismic data over the prospective area. We have 25,146 net acres under lease as of December 31, 2014. During 2014, we drilled two additional wells, one successful exploratory oil well and another exploratory oil well which was lost during completion due to mechanical problems. During the fourth quarter our successful well produced 189 Boepd. Our annual average net daily production was 102 Boepd with estimated proved reserves of 167 MBoe.

Mid-Continent. During 2013, the Company leased approximately 116,000 net acres in the Mid–Continent area. There has been recent drilling activity in this area by other operators on a property in close proximity to our lease. As information regarding the development of the property becomes available, we will continue to evaluate our opportunities in this area.

We currently have 229 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 2015 and expect to relinquish control of the leased acreage as the majority will expire in 2015.

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. Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. During 2014, our gas prices, exclusive of hedges, have been higher than last year due to a general increase in gas market prices. During 2014, our oil prices continued to be strong for most of the year although our premium on our Light and Heavy Louisiana Sweet barrels diminished throughout the year. NYMEX oil prices declined severely during the fourth quarter of 2014, with continued lower prices into 2015. As a result of increased U.S. production as well as other global supply and demand factors, crude oil prices declined by nearly 50% during the fourth quarter of 2014. As of March 25, 2015, NYMEX WTI was $49.21 per barrel and the three-year forward curve for NYMEX WTI was $58.83 per barrel. Both oil and gas prices for 2015 are expected to be lower as compared to the average price in 2014, which we anticipate will have a negative impact on our revenues and cash flows. A substantial or extended period of low oil and/or natural gas prices will 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, 2014, 2013 and 2012. 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,
	2014		2013		2012
Net production volumes:
Oil (Bbl)		714,453		884,994		1,103,653
Natural gas (Boe)		2,081,596		2,476,557		3,068,547
Oil equivalents (Boe)		2,796,049		3,361,551		4,172,200
Average sales price per unit:⁽¹⁾
Oil (Bbl)	$	94.70	$	103.52	$	108.28
Natural gas (Mcf)	$	4.84	$	4.24	$	3.45
Oil equivalents (Boe)	$	45.81	$	45.98	$	43.87
Costs and expenses per Boe:
Production and delivery costs	$	9.78	$	10.41	$	8.52
Depreciation, depletion and amortization⁽²⁾	$	56.53	$	126.75	$	28.29
General and administrative expenses	$	5.16	$	6.35	$	4.98

(1)

Average prices presented do not give effect to our derivative contracts, the monetization of oil derivatives during February 2013 or the monetization of oil and gas derivatives during June, July and September 2014. Please see Item 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, 2014, 2013 and 2012 was $24.87, $26.77 and $19.43 per Boe excluding the ceiling test write-downs, respectively.

Net production volumes for the year ended December 31, 2014 were 2,796 MBoe, a 17% decrease from net production of 3,362 for the year ended December 31, 2013. Our net production volumes decreased by 566 MBoe over 2013 net production mainly because production from new wells drilled did not fully offset the decline in production from our more mature wells. Our average oil sales prices decreased by $8.82 per Bbl from $103.52 at December 31, 2013 to $94.70 per Bbl for the year ended December 31, 2014. Our average gas sales prices increased by $0.60 per Mcf from $4.24 per Mcf for the year ended December 31, 2013 to $4.84 per Mcf for the year ended December 31, 2014. Our production and delivery costs decreased by $0.63 per Boe from $10.41 for the year ended December 31, 2013 to $9.78 per Boe for the year ended December 31, 2014 mainly due to lower costs from lower production. Total production and delivery costs decreased by $7.7 million from $35.0 for the year ended December 31, 2013 to $27.3 million for the year ended December 31, 2014. The overall decrease in production and delivery costs was primarily attributable to lower lift boat costs, insurance, labor, tools and supplies.

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.

The following table sets forth information regarding our average net daily production for the years ended December 31, 2014 and 2013:


	Average Net Daily Production for the Year Ended December 31, 2014						Average Net Daily Production for the Year Ended December 31, 2013
	Bbls		Mcf		Boe		Bbls		Mcf		Boe
Offshore
Federal waters⁽¹⁾		458		1,459		701		410		2,274		789
State waters⁽²⁾		600		11,183		2,464		909		17,690		3,857
Onshore
Texas and Louisiana⁽³⁾		802		21,432		4,374		988		20,579		4,418
Resource Plays
Mid-Continent and California		97		144		121		118		168		146
Total		1,957		34,218		7,660		2,425		40,711		9,210

(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, 2014:


	Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters⁽¹⁾		10.0		9.0		3.0		2.7		13.0		11.7
State waters⁽²⁾		5.0		3.6		8.0		6.4		13.0		10.0
Onshore
Texas and Louisiana⁽³⁾		3.0		2.8		17.0		12.6		20.0		15.4
Resource Plays
Mid-Continent and California		12.0		7.2		—		—		12.0		7.2
Total		30.0		22.6		28.0		21.7		58.0		44.3

(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 and to transmission companies. All of our offshore and shallow water production and onshore gas production is connected to a pipeline, except for the East Cox Bay field whose temporary production facilities will be replaced with permanent facilities during 2015. Generally our onshore oil production is stored in tanks and delivered to market by trucks.

We have been selling to our customers discussed 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 some customers and discuss the credit worthiness of our other 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, 2014, 2013 and 2012 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 September 30, 2015 and represent 57% of our production during December 2014. 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 our commitments require 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 was 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, 2014, 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 term loan 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 may delay 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 released 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. 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 become regulated as hazardous wastes if such wastes have hazardous characteristics.

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

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.

Underground Injection Wells

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. In response to these concerns, regulators in some states are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission, or RRC, on October 28, 2014, adopted new oil and gas permit rules for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. 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 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 several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.

From time to time Congress has 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. Some states and local jurisdictions have banned hydraulic fracturing within their borders altogether. 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.

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 also 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 the first half of 2015. These existing or any future studies could spur initiatives to regulate hydraulic fracturing under the SDWA or under newly established legislation.

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.

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. In addition, in December 2014, the Bureau of Ocean Energy Management issued a final rule, effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. If an unauthorized oil discharge or substantial threat of an unauthorized discharge were to occur, we may be liable for response costs and natural resource 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 December 2014, the EPA published proposed regulations to revise the National Ambient Air Quality Standard for ozone, recommending a standard between 65 to 70 parts per billion, or ppb, for both the 8-hour primary and secondary standards protective of public health and public welfare. EPA requested public comments on whether the standard should be set as low as 60 ppb or whether the existing 75 ppb standard should be retained. EPA anticipates issuing a final rule by October 1, 2015. If EPA lowers the ozone standard, states could be required to implement new more stringent regulations, which could apply to our exploration, development and production operations. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

Climate Change

The EPA has 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 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. For example, California, where we have operations, has adopted a cap and trade program and we are required to obtain allowances for our greenhouse gas emissions. 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.

In addition, on January 14, 2015, the Obama Administration announced that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025.

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. Our offshore operations are particularly at risk from severe climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of 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. Such delays could have an adverse effect on our operations on federal lands.

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. 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. For example, in March 2014, the U.S. Fish and Wildlife Service listed as threatened the lesser prairie chicken, whose habitat includes portions of Texas and the Mid-Continent region, where we operate. As a result, landowners and drilling companies are restricted from undertaking activities that harm the lesser prairie chicken without a permit. Landowners and businesses can, however, enter into certain range-wide conservation planning agreements to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee in order to limit the regulatory impact of the species’ presence. We believe we are in substantial compliance with the requirements of the ESA. 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, 2014, 2013 and 2012.

Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2015 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 (“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, 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 (“NGA”), the Natural Gas Policy Act of 1978 (“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.

We may not be able to continue as a going concern.

The financial statements included in this annual report have been prepared using the going concern assumption, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The accompanying financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. The Company has substantial debt due during 2015, including $238 million of 12.5% senior secured notes due October 1, 2015 (the “Senior Secured Notes”) and $85 million under the Term Loan Facility due July 2, 2015, if the Senior Secured Notes have not been refinanced by this date. The $85 million under the Term Loan Facility is not due until September 12, 2016, if the Senior Secured Notes are refinanced prior to July 2, 2015. Accordingly, the outstanding amounts of Senior Secured Notes and the Term Loan Facility have been classified as current liabilities. The Company is actively working with investment banking advisors to evaluate alternative financing sources. No assurance can be given that such financing will be available on terms that are acceptable to the Company, or at all. Additionally, we will not make our scheduled interest payment to the holders of the Senior Secured Notes due on April 1, 2015. However, under the terms of the indenture for the Senior Secured Notes, there is a 30-day grace period during which we could elect to make the interest payment and cure any potential event of default for non-payment. Absent payment of the interest by the end of the cure window on May 1, 2015, we will be in default under the indenture for the Senior Secured Notes, which will result in the acceleration of our obligation to repay all principal and interest due under the Senior Secured Notes.

If we do not make our scheduled interest payment to the holders of the Senior Secured Notes due on April 1, 2015, the non-payment will also constitute a default under the Fifth Amended and Restated Credit Agreement with Wilmington Trust, National Association, as administrative agent and the lenders party thereto (the “Fifth Amended and Restated Credit Agreement”). During the continuance of such default, our rights and the rights of our subsidiaries pursuant to the Fifth Amended and Restated Credit Agreement will be impacted, among other things, as follows: (i) the borrowers will not have a consent right to any assignments of loans by the lenders, (ii) any and all net proceeds received by or for the account of the Company or our subsidiaries from certain asset dispositions, casualty events, and condemnations, and certain other receipts of cash out of the ordinary course of business (including future tax refunds) must be applied to prepay the term loans without the benefit of any reinvestment or restoration rights and without the benefit of a $5,000,000 exclusion for certain asset disposition proceeds, (iii) we and our subsidiaries will not be permitted to receive regularly scheduled payments on account of any subordinated obligations owed to them by another loan party without the consent of the majority lenders, (iv) we and our subsidiaries will not be able to utilize the basket in the asset disposition covenant which permits dispositions of any oil and gas properties to which no proved reserves are attributed that are sold for fair market value for cash to a non-affiliate, and (v) we and our subsidiaries will not be able to utilize the basket in the asset disposition covenant which permits dispositions of oil and gas properties to which proved reserves are attributed that are sold for fair market value for cash to a non-affiliate in an amount in the aggregate (taking into account all such sales of the Company and our subsidiaries) not in excess of $10,000,000 for all such dispositions in any 12-month period. Additionally, if we do not make our scheduled interest payment to the holders of the Senior Secured Notes by May 1, 2015, the non-payment will also constitute an event of default under the Fifth Amended and Restated Credit Agreement at which time the administrative agent at any time and from time to time may, and upon written instruction from the majority lenders will, accelerate our obligation to repay all principal and interest due under the Fifth Amended and Restated Credit Agreement.

Without making the required interest payment, undertaking a successful refinancing or accessing additional liquidity, the Company will not be able to fund its commitments, including the April 1, 2015 interest payment, to the holders of the Senior Secured Notes or the lenders under the Term Loan Facility and will be in default under the Senior Secured Notes and the Term Loan Facility. If these defaults occur, the Company will be unable to continue as a going concern.

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 cash on hand, however, our financing needs may require us to alter or increase our capitalization substantially. If the Senior Secured Notes are not refinanced prior to July 2, 2015, the amount outstanding under the Term Loan Facility becomes due on that date, 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 additional capital is needed, we may not be able to obtain debt or equity financing or may even be required to pay down the amount outstanding under our Term Loan Facility on July 2, 2015. If cash generated by operations is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our crude oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

The covenants in the indenture governing our Senior Secured Notes and our Term Loan 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 Secured Notes and our Term Loan Facility could have important consequences for our operations, including:

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

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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;

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

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limiting management’s discretion in operating our business;

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

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controlling our ability to hedge our production;

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

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

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making us vulnerable to increases in interest rates, because debt under our Term Loan 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 restrictions in the indenture governing the Senior Secured Notes and our Term Loan Facility, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. We will not make our scheduled interest payment to the holders of the Senior Secured Notes due on April 1, 2015. However, under the terms of the indenture for the Senior Secured Notes, there is a 30-day grace period during which we could elect to make the interest payment and cure any potential event of default for non-payment. Absent payment of the interest by the end of the cure window on May 1, 2015, we will be in default under the indenture for the Senior Secured Notes, which will result in the acceleration of our obligation to repay all principal and interest due under the Senior Secured Notes. If we do not make our scheduled interest payment to the holders of the Senior Secured Notes due on April 1, 2015, the non-payment will also constitute a default under the Fifth Amended and Restated Credit Agreement with Wilmington Trust, National Association, as administrative agent and the lenders party thereto (the “Fifth Amended and Restated Credit Agreement”). During the continuance of such default, our rights and the rights of our subsidiaries pursuant to the Fifth Amended and Restated Credit Agreement will be impacted, among other things, as follows: (i) the borrowers will not have a consent right to any assignments of loans by the lenders, (ii) any and all net proceeds received by or for the account of the Company or our subsidiaries from certain asset dispositions, casualty events, and condemnations, and certain other receipts of cash out of the ordinary course of business (including future tax refunds) must be applied to prepay the term loans without the benefit of any reinvestment or restoration rights and without the benefit of a $5,000,000 exclusion for certain asset disposition proceeds, (iii) we and our subsidiaries will not be permitted to receive regularly scheduled payments on account of any subordinated obligations owed to them by another loan party without the consent of the majority lenders, (iv) we and our subsidiaries will not be able to utilize the basket in the asset disposition covenant which permits dispositions of any oil and gas properties to which no proved reserves are attributed that are sold for fair market value for cash to a non-affiliate, and (v) we and our subsidiaries will not be able to utilize the basket in the asset disposition covenant which permits dispositions of oil and gas properties to which proved reserves are attributed that are sold for fair market value for cash to a non-affiliate in an amount in the aggregate (taking into account all such sales of the Company and our subsidiaries) not in excess of $10,000,000 for all such dispositions in any 12-month period. Additionally, if we do not make our scheduled interest payment to the holders of the Senior Secured Notes by May 1, 2015, the non-payment will also constitute an event of default under the Fifth Amended and Restated Credit Agreement at which time the administrative agent at any time and from time to time may, and upon written instruction from the majority lenders will, accelerate our obligation to repay all principal and interest due under the Fifth Amended and Restated Credit Agreement.

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.

For example, NYMEX oil prices declined severely during the fourth quarter of fiscal 2014 with continued lower prices in the first quarter of fiscal 2015. The West Texas Intermediate (“WTI”) crude oil price per barrel for the period from January 1, 2014 to December 31, 2014 ranged from a high of $107.26 to a low of $53.27 in the last calendar quarter of fiscal 2014, a decrease of 50.3%, and the NYMEX natural gas price per MMBtu for the period January 1, 2014 to December 31, 2014 ranged from a high of $6.15 to a low of $2.89, a decrease of 53%. As of March 25, 2014, the spot market price for WTI was $49.21. The speed and severity of the decline in oil prices during the third quarter of our 2014 fiscal year and the continued lower prices in the fourth quarter of our fiscal year 2014 has materially affected our results of operations. Both oil and gas prices for 2015 are expected to be lower as compared to the average price in 2014, which we anticipate will have a negative impact on our revenues and cash flows in the first quarter of 2015. 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. 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 sustained periods of low prices for crude oil or natural gas would materially limit 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.

Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related restrictions in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In response to the Deepwater Horizon explosive incident and resulting oil spill in the Gulf of Mexico in April 2010, the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement, each agencies of the U.S. Department of the Interior (“DOI”), have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. These governmental agencies have implemented and enforced new rules, Notices to Lessees and Operators (“NTLs”) and temporary drilling moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities. Compliance with these added more stringent regulatory restrictions in addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development and oil spill-response plans could adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, developing and implementing new, more restrictive requirements such as, for example, the 2013 amendments to the federal Workplace Safety Rule regarding the utilization of a more comprehensive safety and environmental management system, (“SEMS”), which amended rule is sometimes referred to as SEMS II, and, more recently, the August 2014 Advanced Notice of Proposed Rulemaking that ultimately seeks to bolster the offshore financial assurance and bonding program.

Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities. If similar material spill incidents were to occur in the future, 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 laws and regulations regarding offshore oil and natural gas exploration and development. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

Further, the deepwater areas of the Gulf of Mexico (as well as international deepwater locations) lack the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, despite our oil spill-response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Deepwater Horizon incident. The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Our estimates of future decommissioning 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 decommissioning obligations, including the plugging and abandonment of inactive, non-producing wells, removal of inactive or damaged platforms, facilities and equipment, and the restoration of land or seabed at the end of oil and natural gas production operations. These decommissioning 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 decommissioning costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, and decommissioning 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 decommissioning 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 decommissioning 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 decommissioning obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

Moreover, governmental authorities may amend existing, or adopt new, laws or regulations that impose more stringent requirements in how we provide financial assurance for these decommissioning obligations. For example, offshore exploration, development and production operators such as us are typically required to comply with stringent bonding requirements so as to assure that operators have the financial capacity to satisfy decommissioning obligations when they become due. Only recently, in August 2014, the BOEM published an Advance Notice of Proposed Rulemaking, pursuant to which it seeks to bolster its current bonding requirements for offshore oil and gas operations. Although it is not possible at this time to predict what, if any, changes BOEM would make to current bonding requirements, any such legal requirements that impose more stringent financial assurance requirements that we or other offshore operators in the industry were unable to fully satisfy could cause BOEM to require the covered offshore operations on federal leases to be suspended or terminated that, in the case of our operations, could materially and adversely affect our financial condition, cash flows and results of operations

In addition, the timing for pursuing decommissioning activities has accelerated for operators in the U.S. Gulf of Mexico following the DOI’s issuance of 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 Flatt’s Guitar proved undeveloped reserves.

Proved undeveloped reserves related to Flatt’s 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.

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, Ken Young, our Chief Operating Officer, Michael Willis, our Senior Vice President and a member of our Board of Directors, Jeff T. Craycraft, our Chief Financial Officer and Treasurer, and Elizabeth A. Barr, our Chief Administrative Officer. 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.

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, we will not be the operator on all of our future properties and therefore we 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 all but one of our wells (excluding our wells in Oklahoma). 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 catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Katrina, Rita, Gustav and Ike, as well as the 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:

•

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

•

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

•

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

•

impose substantial liabilities for pollution resulting from operations; and

•

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 and Occupational Health and Safety Matters” 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:

•

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

•

our ability to acquire additional 3-D seismic data;

•

our ability to identify and acquire new exploratory prospects;

•

our ability to develop existing prospects;

•

our ability to continue to retain and attract skilled personnel;

•

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

•

the results of our drilling program;

•

hydrocarbon prices; and

•

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.

The EPA has 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 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. 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.

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. Only recently, on January 14, 2015, the Obama Administration announced that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. 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.

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.

In addition, certain governmental reviews 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 also 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 the first half of 2015. These existing or future studies 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 Term Loan 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 may 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.

In recent years, legislation has been proposed legislation that would, if enacted into law, make significant changes to U.S. federal income 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. Such tax legislation 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, (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 and (iv) increases in tax rates. 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.

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; and (ii) 288 square feet of office space in Bakersfield, California, which is leased on a month to month basis.

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. On April 24, 2014, the Company filed a Combined Petition for Panel Rehearing and for Rehearing En Banc. In July 2014, our Combined Petition for Panel Rehearing and for Rehearing En Banc was denied. On October 17, 2014, the Company filed a Petition for a Writ of Certiorari with the Supreme Court of the United States seeking review of the court of appeals’ decision. In January 2015, the Supreme Court denied our Petition for a Writ of Certiorari.

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 27, 2014, there were 204 holders of record of our common stock. The Company did not pay dividends during 2014. 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. 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, 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, 2014, 2013, 2012, 2011 and 2010 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.


	2014			2013			2012			2011			2010
In thousands
Statement of Operations Data:
Revenues
Gas sales	$	60,422		$	62,953		$	63,535		$	87,064		$	79,331
Oil sales		67,658			91,618			119,504			113,722			83,122
Gains (losses) on derivatives, net		15,056			(5,038	)		20,769			13,650			17,417

Total revenues		143,136			149,533			203,808			214,436			179,870
Costs and expenses:
Production and delivery costs		27,339			35,003			35,529			34,326			31,569
Production taxes Workover costs		7,468 2,143			7,965 3,729			9,314 2,772			10,259 7,730			5,732 10,470
Depreciation, depletion and amortization		158,064			426,061			118,041			71,763			67,312
General and administrative expenses		14,434			21,359			20,780			28,861			16,731

Total operating expenses		209,448			494,117			186,436			152,939			131,814

Income (loss) from operations		(66,312	)		(344,584	)		17,372			61,497			48,056
Other income (expenses):
Interest income		191			117			78			244			276
Interest expense		(34,829	)		(29,686	)		(21,315	)		(17,198	)		(9,057	)
Gain on extinguishment of senior secured notes		6,718			—			—			—			—
Loss on equity investment		—			—			—			(2,044	)		(5,156	)
Loss on sale or disposal of inventory		—			—			(954	)		(20	)		(1,463	)
Other income (expense), net		(960	)		(126	)		431			204			434

Total other income (expenses)		(28,880	)		(29,695	)		(21,760	)		(18,814	)		(14,966	)

Income (loss) before taxes		(95,192	)		(374,279	)		(4,388	)		42,683			33,090
Income tax provision (benefit)		(10,677	)		(134,080	)		(1,796	)		17,295			5,794

Net income (loss) including noncontrolling interest		(84,515	)		(240,199	)		(2,592	)		25,388			27,296
Net income attributable to noncontrolling interest		1,279			1,218			1,314			1,524			1,682

Net income (loss) attributable to RAAM Global	$	(85,794	)	$	(241,417	)	$	(3,906	)	$	23,864		$	25,614

Statement of Cash Flows Data:
Capital expenditures	$	111,394		$	126,320		$	180,500		$	228,178		$	86,936
Cash flow provided by (used in):
Operating activities		42,307			78,742			128,278			172,928			114,209
Investing activities		(115,154	)		(52,652	)		(155,007	)		(246,034	)		(87,838	)
Financing activities		71,636			(3,903	)		43,657			43,817			25,773
Balance Sheet Data (at period end):
Cash and cash equivalents	$	89,647		$	90,858		$	68,671		$	51,743		$	81,032
Oil and gas properties, net		242,100			287,118			654,268			615,907			461,363
Total assets		391,626			426,612			779,454			744,552			621,698
Total debt, including current portion		326,559			256,111			254,541			204,634			152,653
Total shareholders’ equity		(37,759	)		50,015			293,549			302,391			295,201

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 mainly located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas 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 and optimizing our acreage positions. Our current drilling program focuses on our core area in Breton Sound. This has historically been a very successful field for us. We are currently in the process of drilling one well in Breton Sound. We expect this well to reach total depth late in the second quarter of 2015. Based on the outcome of this well, we have three additional prospects in the Breton Sound area that we hope to drill later in 2015.

We have recently discovered a new field, East Cox Bay, in the shallow waters of the Gulf of Mexico that has comparable 3D seismic signatures to our Breton Sound field. In February 2015, we successfully brought our first well in this field online. As of March 27, 2015, this well was producing at 442 Boe per day. We currently have six prospects under lease in this field. We feel this field could become a key area for us and plan to drill several of these prospects later in 2015.

At December 31, 2014, based on the reserve reports, our estimated total proved oil and natural gas reserves, of which all are estimated proved developed reserves, were approximately 8,898 MBoe. Oil comprises approximately 32% of our total estimated proved reserves. For the year ended December 31, 2014, daily production averaged 7,660 Boepd.

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. The recent declines in oil prices have adversely affected our financial position and results of operations and sustained periods of low prices for oil and natural gas are likely to 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.


	2014
	2014			Q1		Q2			Q3			Q4
Oil:
Average price before derivatives ($/Bbl)⁽¹⁾	$	94.70		$	100.03	$	104.29		$	98.53		$	73.86
Average price differentials⁽²⁾	$	2.24		$	5.52	$	5.61		$	1.74		$	(3.91	)
Natural Gas:
Average price before derivatives ($/Mcf)⁽¹⁾	$	4.84		$	5.33	$	5.20		$	4.63		$	4.10
Average price differentials⁽²⁾	$	(0.16	)	$	0.18	$	(0.19	)	$	(0.15	)	$	(0.48	)

	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

(1)

Average prices presented do not give effect to our derivative contracts, the monetization of oil derivatives during February 2013 or the monetization of oil and gas derivatives during June, July and September 2014. Please see “— Oil and Gas Derivatives” for a discussion of our derivative activities.

(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. As a result of increased U.S. production as well as other global supply and demand factors, NYMEX crude oil prices declined by nearly 50% during the fourth quarter of 2014. As of March 25, 2015, NYMEX WTI was $49.21 per barrel and the three-year forward curve for NYMEX WTI was $58.83 per barrel.

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. 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.

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, 2014, 2013 and 2012.


	Year Ended December 31,
	2014			2013			2012
Average daily production:
Oil (Bbl per day)		1,957			2,425			3,015
Natural gas (Mcf per day)		34,218			40,711			50,304
Oil equivalents (Boe per day)		7,660			9,210			11,399
Average prices:⁽¹⁾
Oil ($/Bbl)	$	94.70		$	103.52		$	108.28
Natural gas ($/Mcf)	$	4.84		$	4.24		$	3.45
Oil equivalents ($/Boe)	$	45.81		$	45.98		$	43.87
Production and delivery costs ($/Boe)	$	9.78		$	10.41		$	8.52
General and administrative expense ($/Boe)	$	5.16		$	6.35		$	4.98
Net loss attributable to RAAM Global (in thousands)	$	(85,794	)	$	(241,417	)	$	(3,906	)
Adjusted EBITDA⁽²⁾ (in thousands)	$	76,268		$	84,730		$	143,731

(1)

Average prices presented do not give effect to our derivative contracts, the monetization of oil derivatives during February 2013 or the monetization of oil and gas derivatives during June, July and September 2014. Please see “— Oil and Gas Derivatives” for a discussion of our derivative activities.

(2)

Adjusted EBITDA as used herein represents net income (loss) before net (gains) losses on derivatives, net of cash settlements received or paid, 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,
	2014			2013			2012
	(In thousands)
Net loss attributable to RAAM Global	$	(85,794	)	$	(241,417	)	$	(3,906	)
Net (gains) losses on derivatives, net of cash settlements received or paid		(20,154	)		4,480			10,077
Interest expense		34,829			29,686			21,315
Depreciation, depletion and amortization		158,064			426,061			118,041
Income taxes		(10,677	)		(134,080	)		(1,796	)

Adjusted EBITDA	$	76,268		$	84,730		$	143,731

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 (benefit) 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 (benefits) expenses and (b) deferred federal, state, and local income tax (benefits) expenses.

Results of Operations

The following table sets forth the results of operations for the years ended December 31, 2014, 2013 and 2012. 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,
	2014			2013			2012
	(dollars in thousands)
Revenues:
Gas sales	$	60,422		$	62,953		$	63,535
Oil sales		67,658			91,618			119,504
Gains (losses) on derivatives, net		15,056			(5,038	)		20,769

Total revenues		143,136			149,533			203,808
Costs and expenses:
Production and delivery costs		27,339			35,003			35,529
Production taxes		7,468			7,965			9,314
Workover costs		2,143			3,729			2,772
Depreciation, depletion and amortization		158,064			426,061			118,041
General and administrative expenses		14,434			21,359			20,780

Total operating expense		209,448			494,117			186,436

Income (loss) from operations		(66,312	)		(344,584	)		17,372
Other income (expenses):
Interest expense, net		(34,638	)		(29,569	)		(21,237	)
Gain on extinguishment of senior secured notes		6,718			—			—
Loss on sale or disposal of inventory		—			—			(954	)
Other income (expense), net		(960	)		(126	)		431

Total other income (expenses)		(28,880	)		(29,695	)		(21,760	)

Loss before taxes		(95,192	)		(374,279	)		(4,388	)
Income tax benefit		(10,677	)		(134,080	)		(1,796	)

Net loss including noncontrolling interest		(84,515	)		(240,199	)		(2,592	)
Net income attributable to noncontrolling interest		1,279			1,218			1,314

Net loss attributable to RAAM Global	$	(85,794	)	$	(241,417	)	$	(3,906	)

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Revenues

Oil and natural gas production. Oil and natural gas production for the year ended December 31, 2014 decreased to 2.8 MMBoe from 3.4 MMBoe for the year ended December 31, 2013. Gas and oil production for the year ended December 31, 2014 decreased by 16% and 19%, respectively, over the year ended December 31, 2013. The decrease in production during 2014 was mainly because production realized from the drilling of new wells during 2014 did not fully offset the normal production declines from our more mature wells.

Total revenues. Total revenues for the year ended December 31, 2014 decreased to $143.1 million from $149.5 million for the year ended December 31, 2013. Gas revenues (exclusive of derivatives) decreased by $2.5 million due to lower gas volumes. Gas prices increased by 14% from an average price of $4.24 for the year ended December 31, 2013 to an average gas price of $4.84 for the year ended December 31, 2014.

Oil revenues (exclusive of derivatives) decreased by $24.0 million due to lower oil volumes and lower oil prices. Oil prices decreased by 9% from an average oil price of $103.52 for the year ended December 31, 2013 to an average oil price of $94.70 for the year ended December 31, 2014.

Gains (losses) on derivatives, net. Gains (losses) on derivatives, net, were a gain of $15.1 million for the year ended December 31, 2014 as compared to a loss of $5.0 million for the year ended December 31, 2013. The fluctuation from year to year is mainly due to the large decrease in oil prices as of the balance sheet date resulting in a large increase in the fair values of our outstanding derivative contracts as of December 31, 2014 as compared to those at December 31, 2013.

During 2014, the Company’s average price of $45.81 per Boe from the sale of oil and natural gas was approximately the same as its average sales price of $45.98 per Boe as of December 31, 2013. Natural gas prices were approximately 14% higher during 2014 over 2013 while oil prices were approximately 9% lower during 2014 over 2013.

Operating Costs and Expenses

Production and delivery costs. Our production and delivery costs for 2014 decreased in total to $27.3 million, or $9.78 per Boe, from $35.0 million in 2013, or $10.41 per Boe. The decrease in production and delivery costs was primarily attributable to lower lift boat costs, insurance, labor, and tools and supplies.

Production taxes. Production taxes for 2014 decreased to $7.5 million from $8.0 million in 2013. 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 and gas revenues between periods, partially offset by a higher gas severance tax rate.

Workover costs. Our workover costs for 2014 decreased to $2.1 million, or $0.77 per Boe, from $3.7 million in 2013, or $1.11 per Boe. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. Workover projects performed during 2014 had lower lift boat and transportation costs than those performed during 2013.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for 2014 decreased to $158.1 million from $426.1 million in 2013. Depreciation, depletion and amortization for the year ended December 31, 2014 decreased to $56.53 per Boe including the effect of the ceiling test write-downs ($24.87 per Boe, excluding the ceiling test write-downs) down from $126.75 per Boe including the effect of the ceiling test write-downs during 2013 ($26.77 per Boe, excluding the ceiling test write-downs) for the year ended December 31, 2013. The decrease in depreciation, depletion and amortization was primarily due to “ceiling test” write-downs of $88.5 million during 2014 as compared to write downs of $336.0 million during 2013. Of the $88.5 million in ceiling test write-downs recorded during 2014, $30.2 million was related to revisions in the Company’s reserves due to our current debt position causing us to be unable to demonstrate an ability to develop our proved undeveloped reserves and certain of our proved developed non-producing reserves.

General and administrative expenses. General and administrative expenses decreased to $14.4 million in 2014 down from $21.4 million in 2013. The decrease in general and administrative expenses was primarily due to stock-based compensation awarded to employees for sales of certain non-core assets during 2013, which did not recur in 2014, as well as lower consultant costs and lower data processing costs, partially offset by higher bank transactions fees in 2014.

Interest expense, net. Net interest expense increased to $34.6 million in 2014 up from $29.6 million in 2013 due to higher debt levels and a higher weighted average interest rate. Debt balances averaged $275.3 million during 2014 and $250.0 million during 2013. Interest rates averaged 12.1% during 2014 and 11.9% during 2013. Amounts of interest expense capitalized to net oil and gas properties during 2014 and 2013 are discussed in Item 8, “Notes to Consolidated Financial Statements—Note 2, Significant Accounting Policies.”

Other income (expense), net. For 2014, other expense was $960,000 as compared to other expense of $126,000 in 2013. The increase was mainly due to inventory write downs during 2014 due to obsolescence of certain pipe inventory, partially offset by certain transition service fees received by the Company during 2014.

Income tax benefit. For 2014, the Company recorded an income tax benefit of $10.7 million as compared to an income tax benefit of $134.1 million for 2013. Income tax benefits recognized were based on effective tax rates of 11.2% for 2014 and 35.8% for 2013. The Company’s effective tax rate differs from the statutory U.S. federal income tax rate primarily because of state and local income taxes, tax percentage depletion in excess of cost basis and changes in the valuation allowance.

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, 2012. 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.

Gains (losses) on derivatives, net. 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 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.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from shareholders, borrowings under our Term Loan 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. The Company has substantial debt due during 2015, including $238.0 million of Senior Secured Notes due October 1, 2015 and $85.0 million under the Term Loan Facility due July 2, 2015, if the Senior Secured Notes have not been refinanced by this date. The $85.0 million under the Term Loan Facility is not due until September 12, 2016, if the Senior Secured Notes are refinanced prior to July 2, 2015. We are actively working with investment banking advisors to pursue alternative financing. No assurance can be given that such financing will be available on terms that are acceptable to us, or at all.

Additionally, we will not make our scheduled interest payment to the holders of the Senior Secured Notes due on April 1, 2015. However, under the terms of the indenture for the Senior Secured Notes, there is a 30-day grace period during which we could elect to make the interest payment and cure any potential event of default for non-payment by May 1, 2015. Absent payment of the interest by the end of the cure window on May 1, 2015, we will be in default under the indenture for the Senior Secured Notes, which will result in the acceleration of our obligation to repay all principal and interest due under the Senior Secured Notes.

If we do not make our scheduled interest payment to the holders of the Senior Secured Notes due on April 1, 2015, the non-payment will also constitute a default under the Fifth Amended and Restated Credit Agreement. During the continuance of such default, our rights and the rights of our subsidiaries pursuant to the Fifth Amended and Restated Credit Agreement will be impacted, among other things, as follows: (i) the borrowers will not have a consent right to any assignments of loans by the lenders, (ii) any and all net proceeds received by or for the account of the Company or our subsidiaries from certain asset dispositions, casualty events, and condemnations, and certain other receipts of cash out of the ordinary course of business (including future tax refunds) must be applied to prepay the term loans without the benefit of any reinvestment or restoration rights and without the benefit of a $5,000,000 exclusion for certain asset disposition proceeds, (iii) we and our subsidiaries will not be permitted to receive regularly scheduled payments on account of any subordinated obligations owed to them by another loan party without the consent of the majority lenders, (iv) we and our subsidiaries will not be able to utilize the basket in the asset disposition covenant which permits dispositions of any oil and gas properties to which no proved reserves are attributed that are sold for fair market value for cash to a non-affiliate, and (v) we and our subsidiaries will not be able to utilize the basket in the asset disposition covenant which permits dispositions of oil and gas properties to which proved reserves are attributed that are sold for fair market value for cash to a non-affiliate in an amount in the aggregate (taking into account all such sales of the Company and our subsidiaries) not in excess of $10,000,000 for all such dispositions in any 12-month period. Additionally, if we do not make our scheduled interest payment to the holders of the Senior Secured Notes by May 1, 2015, the non-payment will also constitute an event of default under the Fifth Amended and Restated Credit Agreement at which time the administrative agent at any time and from time to time may, and upon written instruction from the majority lenders will, accelerate our obligation to repay all principal and interest due under the Fifth Amended and Restated Credit Agreement.

Without access to additional liquidity, we will not be able to fund our commitments to the holders of the Senior Secured Notes, including the April 1, 2015 interest payment, or the lenders under the Term Loan Facility and will be in default under the Senior Secured Notes and the Term Loan Facility. If these defaults occur, we will be unable to continue as a going concern.

As of December 31, 2014, the Company had $89.6 million in cash and cash equivalents, as well as $13.8 million of restricted cash in escrow for plugging and abandonment work. Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline into 2015. These declines in commodity prices have negatively impacted revenues, earnings and cash flows and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. Over the next six months, the Company intends to fund general and administrative expenses, interest payments, and capital expenditures from cash on hand and cash flows from operations. The detailed budget below provides more information on our planned capital expenditures during 2015.

We have a total capital expenditure budget of $62 million for 2015. During 2014, we invested $111 million on capital expenditures. 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 remain depressed or further 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.

We currently expect that $62 million of our 2015 capital budget will be funded from our cash flow from operations in 2015, including projected cash flow from new wells, and existing cash balances. We have pre-funded $13.8 million of plugging and abandonment costs for work expected to be performed during 2015. This balance is in an escrow account and is recorded as restricted cash. We expect to add another $7 million incrementally during 2015 to fund required plugging and abandonment projects.

Capital Expenditure Budget

The 2015 capital budget consists of:

•

$10 million for geological and geophysical costs, including leasing;

•

$4 million for offshore Gulf of Mexico drilling and development;

•

$42 million for offshore State waters drilling and development;

•

$1 million for onshore conventional drilling and development; and

•

$5 million for California drilling and development.

Term Loan Facility

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

Interest is payable quarterly on September 30, December 31, March 31, and June 30 of each year, which commenced on September 30, 2014.

The proceeds of the term loan incurred under the Fifth Amended and Restated Credit Agreement were or will be used to (a) repay all expenses, fees or indemnitees outstanding under the Fourth Amended and Restated Credit Agreement dated as of November 29, 2011, (b) finance capital expenditures associated with the Company’s oil and gas properties, (c) provide working capital for the Company’s operations and (d) pay transaction fees and expenses incurred in connection with the transactions contemplated by the Fifth Amended and Restated Credit Agreement. The Fifth Amended and Restated Credit Agreement contains customary restrictions on, among other things the Company’s ability to incur debt, grant liens on their property, make dispositions or investments, enter into mergers or issue new securities, make distributions, enter into affiliate transactions, enter into hedging contracts, amend their organizational documents and create new subsidiaries. In addition, the Fifth Amended and Restated Credit Agreement requires the Company to maintain the following financial covenants as defined in the agreement: (i) a minimum Current Ratio of 1.0:1.0 as of the end of each fiscal quarter (per the terms of the credit agreement, the Senior Secured Notes and Term Loan Facility are excluded in the calculation of the Current Ratio), (ii) a maximum First Lien Leverage Ratio of 2.0:1.0 as of the end of each fiscal quarter for the four immediately preceding fiscal quarters and (iii) a minimum PDP Asset Coverage Ratio of 1.0:1.0 as of January 1, 2015 and 1.1:1.0 as of April 1, 2015, July 1, 2015, January 1, 2016 and July 1, 2016. As of December 31, 2014, the Company was in compliance with all of these financial covenants.

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 our previous 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 Secured Notes due 2015 (the “Additional 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 Secured Notes due 2015 (the “New Additional Notes,” and together with the Original and Additional Notes, the “Senior Secured 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 previous 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, 2014, a total of $238.0 million notional amount of the Senior Secured Notes was outstanding. The carrying amount of the Senior Secured Notes including unamortized premium and discount was $238.4 million as of December 31, 2014.

The Senior Secured Notes are guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our Term Loan Facility. The Senior Secured 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 Term Loan Facility, subject to certain exceptions. Pursuant to an intercreditor agreement, dated as of September 24, 2010, the lien securing the Senior Secured Notes is subordinated and junior to liens securing our Term Loan 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, 2014, 2013 and 2012.


	Year Ended December 31,
	(dollars in thousands)
	2014			2013			2012
Net cash provided by operating activities	$	42,307		$	78,742		$	128,278
Net cash used in investing activities		(115,154	)		(52,652	)		(155,007	)
Net cash provided by (used in) financing activities		71,636			(3,903	)		43,657

Net (decrease) increase in cash and equivalents	$	(1,211	)	$	22,187		$	16,928

Cash Flows Provided by Operating Activities

Cash provided by operating activities was $42.3 million during 2014 as compared to cash provided by operating activities of $78.7 million during 2013. The decrease in operating cash flows during 2014 was principally attributable to changes in derivative balances and higher settlements of asset retirement obligations during 2014 as compared to 2013.

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 Secured Notes at year-end 2013 as compared to year-end 2012.

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 $115.2 million during 2014 as compared to cash used in investing of $52.7 million during 2013. Cash used in investing activities increased in 2014 as compared to 2013 primarily because 2013 capital expenditures of $126.3 million were offset by $68.9 million of proceeds from property sales and property sales during 2014 were only $0.5 million. Capital expenditures of $111.4 million during 2014 were lower than 2013 capital expenditures of $126.3 million primarily because of decreased drilling onshore Texas and the joint venture arrangement for drilling in Louisiana state waters under which the Company has minor working interests for the drilling phases of projects.

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).

Our capital expenditures for drilling, development and acquisition costs for the years ended December 31, 2014, 2013 and 2012 are summarized in the following table:


	Year Ended December 31,
	(dollars in thousands)
	2014		2013		2012
Project Area
Federal	$	19,113	$	12,974	$	3,193
State waters		29,451		40,226		64,510
Onshore Texas and Louisiana		34,270		45,070		84,684
Oklahoma, California and Mid-Continent		28,560		28,050		28,113

Total	$	111,394	$	126,320	$	180,500

Cash Flows Provided by (Used in) Financing Activities

Cash provided by financing activities was $71.6 million during 2014 as compared to cash used in financing activities of $3.9 million during 2013. Cash flows provided by financing activities during 2014 consisted of $84.5 million of financing (net of original issue discount) obtained pursuant to a new credit agreement and $4.5 million of borrowings for our insurance premium financing partially offset by payments of $5.9 million on borrowings and $5.2 million on the 2015 Senior Secured Notes, $3.3 million purchase of noncontrolling interest and $2.9 million of deferred loan costs on the new financing.

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.

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. As required by the Fifth Amended and Restated Credit Agreement, the Company’s derivative counterparties are limited to our secured lenders, which helps to minimize any potential non-performance risk. 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, 2014, commodity derivative instruments were in place covering approximately 47% of our projected oil and natural gas sales for 2015 and 41% of our projected oil and natural gas sales for 2016.

As of December 31, 2014, we had entered into the following oil derivative instruments:


	NYMEX Contract Price
	Total Swaps
Period	Volume in Bbls/Mo		Strike Price
2015		22,338	$	89.44
2016		15,335	$	88.12

As of December 31, 2014, we had entered into the following natural gas derivative instruments:


	Total Swaps
Period	Volume in MBtu/Mo		Weighted Average Fixed Price
2015		429,049	$	4.02
2016⁽¹⁾		36,948	$	4.08

(1)	The Company currently only has derivative transactions via swaps for volumes in the first quarter of 2016. The calculation of average hedged volumes is for the full year of 2016.


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


	NYMEX Contract Price
	Sell Call
Period	Volume in MBtu/Mo		Strike Price
2016		240,397	$	4.73

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, 2014 in thousands:


	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
12.50% Notes Due 2015⁽¹⁾	$	260,313	$	260,313	$	—	$	—	$	—
Term Loan Facility Due 2015⁽²⁾		88,188		88,188		—		—		—
Promissory note⁽³⁾		3,472		298		651		651		1,872
Other indebtedness⁽⁴⁾		1,235		1,235		—		—		—
Operating leases⁽⁵⁾		709		569		140		—		—

Total	$	353,917	$	350,603	$	791	$	651	$	1,872

(1)	A principal repayment of $238 million is included in the Less Than 1 Year column. All other amounts represent interest.

(2)	A principal repayment of $85 million is included in the Less Than 1 Year column. All other amounts represent interest.

(3)	Consists of a promissory note with Business Property Lending Inc. in the aggregate principal and interest amount of $3.5 million relating to the construction of our Houston, TX office building.

(4)	Consists of $1.2 million of outstanding indebtedness relating to the financing of the premiums on our annual insurance policy.

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

There were no drilling rig commitments at December 31, 2014.

As of December 31, 2014, the Company has asset retirement obligations of $14.5 million recorded in current liabilities. These are expected to be settled within one year. As of December, 31, 2014, the Company has asset retirement obligations of $30.1 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, 2014, 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 $7.4 million, $8.2 million and $4.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company capitalized interest of $2.0 million, $2.4 million and $6.8 million during the years ended December 31, 2014, 2013 and 2012, 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 $27.9 million and $45.8 million at December 31, 2014 and December 31, 2013, respectively. The Company believes that the unevaluated properties at December 31, 2014 will be substantially evaluated during 2015, 2016 and 2017, 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 $88.5 million, $336.0 million and $37.0 million of non-cash write downs of the carrying value of its proved oil and natural gas properties during the years ended December 31, 2014, 2013 and 2012, respectively, as a result of “ceiling test” limitations. 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, 2012 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. For the year ended December 31, 2014, our estimated proved reserves were prepared by Netherland, Sewell & 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 on the accompanying consolidated balance sheet 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 received a $17.3 million net carry from this unrelated third party. The sale was recorded as a reduction to our net oil and gas properties on the accompanying consolidated balance sheets, with no impact on the statement of opearations because the sale did not significantly alter the relationship between capitalized costs and proved reserves.

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 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 impact on the statement of operations 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 impact on the statement of operations because the sale did not significantly alter the relationship between capitalized costs and proved reserves.

Asset Retirement Obligations

In accordance with the provisions of Financial Accounting Standards Board (“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, 2014 was $44.0 million. The asset retirement liability at December 31, 2014 was $44.6 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. Other critical assumptions used to calculate asset retirement obligations include reserve lives as reported by our independent oil and natural gas reservoir engineering consulting firm, 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 Gains (losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in 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.

Recently Issued Accounting Standards

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 615, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods and services. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect initially applying ASU 2014-09 recognized at the date of initial application. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.

Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU 2014-15 becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

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, 2014, 2013 or 2012. 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 WTI price for crude oil and spot market prices applicable to our United States natural gas production. Pricing for crude oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Hypothetical changes in commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations. However, since it is not possible to accurately predict future changes in commodity prices, this hypothetical change may not necessarily be an indicator of probable future fluctuations. Based on our average daily production for the year ended December 31, 2014, our oil sales would increase or decrease by approximately $7.1 million for each $10.00 per barrel change in crude oil prices and our gas sales would increase or decrease by approximately $12.5 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 will be unable to meet the financial terms of such transactions. As required by the Fifth Amended and Restated Credit Agreement, the Company’s derivative counterparties are limited to our secured lenders, which helps to minimize any potential non-performance risk.

At December 31, 2014, $17.2 million represented the fair value of the commodity derivatives. This $17.2 million was made up of approximately $11.7 million in current assets and $5.5 million in long-term assets. 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. A 10% increase in prices used at December 31, 2014 would have reduced the asset fair value by $3.9 million and a 10% decrease in prices would have increased the asset fair value by $3.7 million.

As of December 31, 2014, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast natural gas production for 2015 and 2016:


		Volume in		NYMEX
	Contract	MMBtus/		Strike
Remaining Contract Term	Type	Month		Price
January 2015 - March 2015	Swap		212,973	$	4.09
January 2015 - December 2015	Swap		375,806	$	4.01
January 2015 - December 2015	Put - Sell		316,430	$	3.50
January 2016	Swap		81,354	$	4.02
January 2016 - March 2016	Swap		120,675	$	4.10
January 2016 - December 2016	Put - Buy		240,397	$	4.00
January 2016 - December 2016	Put - Sell		240,397	$	3.50
January 2016 - December 2016	Call - Sell		240,397	$	4.73

As of December 31, 2014, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast oil production for 2015 and 2016:

Volume in

NYMEX

Contract

BBls/

Strike

Remaining Contract Term

Type

Month

Price

January 2015 - December 2015

Swap

22,338

89.44

January 2016 - December 2016

Swap

15,335

88.12

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 ($1.4 million at December 31, 2014) and the sale of our crude oil and natural gas production, which we market to energy marketing companies and transmission companies ($12.9 million in receivables at December 31, 2014). Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. In order to minimize our exposure to credit risk we request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk. We also have the right to place a lien on our co-owners interest in the well, to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness.

We have not generally required our counterparties to provide collateral to support crude oil and natural gas sales receivables owed to us. 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 previous revolving credit facility, and this exposure will remain under our Term Loan Facility. There was $85.0 million outstanding under the Term Loan Facility at December 31, 2014. We do not believe our interest rate exposure warrants entry into interest rate hedges and have, therefore, not hedged our interest rate exposure.

Item 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, 2014 and 2013, and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2014. 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 8 to the consolidated financial statements, the Company has a working capital deficiency primarily due to the current classification of the outstanding senior secured notes and term loan. This factor raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 8. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Ernst & Young LLP

Louisville, Kentucky

March 31, 2015

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)


	December 31,			December 31,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	89,647		$	90,858
Restricted cash		13,750			—
Accounts receivable, net of $193 and $656 allowance for doubtful accounts in 2014 and 2013, respectively		1,441			5,472
Revenues receivable		12,890			19,517
Deferred tax asset		—			3,938
Commodity derivatives		11,753			—
Prepaid assets		2,305			3,863
Other current assets		4,037			5,103

Total current assets		135,823			128,751
Oil and gas properties (full-cost method):
Properties being amortized		1,560,739			1,432,310
Properties not subject to amortization		27,928			45,752
Less accumulated depreciation, depletion, and amortization		(1,346,567	)		(1,190,944	)

Net oil and gas properties		242,100			287,118
Other assets:
Other capitalized assets, net		6,383			7,252
Commodity derivatives		5,465			1,541
Deferred tax asset		1,712			—
Other		143			1,950

Total other assets		13,703			10,743

Total assets	$	391,626		$	426,612

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)


	December 31,			December 31,
	2014			2013
Liabilities and equity
Current liabilities:
Accounts payable and accrued liabilities	$	35,724		$	28,066
Revenues and severance taxes payable		12,472			17,699
Interest payable - senior secured notes		7,438			7,813
Current taxes payable		—			25
Advances from joint interest partners		586			4,852
Commodity derivatives		—			4,467
Asset retirement obligations		14,525			14,089
Senior secured notes		238,425			—
Debt		85,844			2,626
Deferred income taxes		1,833			—

Total current liabilities		396,847			79,637
Other liabilities:
Asset retirement obligations		30,089			29,138
Long-term debt		2,290			2,448
Senior secured notes		—			251,037
Deferred income taxes		—			14,178
Other long-term liabilities		159			159

Total other liabilities		32,538			296,960

Total liabilities		429,385			376,597
Commitments and contingencies (see Note 13)
Equity:
Common stock, $0.01 par value, 380,000 shares authorized, 61,433 and 61,425 outstanding in 2014 and 2013, respectively		64,157			63,521
Treasury stock at cost, 6,873 shares in 2014 and 2013, respectively		(8,552	)		(8,552	)
Accumulated deficit		(93,235	)		(7,441	)

Total equity attributable to RAAM Global Shareholders		(37,630	)		47,528
Noncontrolling interest		(129	)		2,487

Total equity		(37,759	)		50,015

Total liabilities and equity	$	391,626		$	426,612

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)


	2014			2013			2012
Revenues:
Gas sales	$	60,422		$	62,953		$	63,535
Oil sales		67,658			91,618			119,504
Gains (losses) on derivatives, net		15,056			(5,038	)		20,769

Total revenues		143,136			149,533			203,808
Operating expenses:
Production and delivery costs		27,339			35,003			35,529
Production taxes		7,468			7,965			9,314
Workover costs		2,143			3,729			2,772
Depreciation, depletion and amortization		158,064			426,061			118,041
General and administrative expenses		14,434			21,359			20,780

Total operating expense		209,448			494,117			186,436

Income (loss) from operations		(66,312	)		(344,584	)		17,372
Other income (expenses):
Interest expense, net		(34,638	)		(29,569	)		(21,237	)
Gain on extinguishment of senior secured notes		6,718			—			—
Loss on sale or disposal of inventory		—			—			(954	)
Other income (expense), net		(960	)		(126	)		431

Total other income (expenses):		(28,880	)		(29,695	)		(21,760	)

Loss before taxes		(95,192	)		(374,279	)		(4,388	)
Income tax benefit		(10,677	)		(134,080	)		(1,796	)

Net loss including noncontrolling interest		(84,515	)		(240,199	)		(2,592	)

Net income attributable to noncontrolling interest (net of tax)		1,279			1,218			1,314

Net loss attributable to RAAM Global	$	(85,794	)	$	(241,417	)	$	(3,906	)

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, 2012		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
Issuance of common stock		8			12										1			13
Purchase of noncontrolling interest					624										(3,896	)		(3,272	)
Net income (loss)												(85,794	)		1,279			(84,515	)

Balance, December 31, 2014		61,433		$	64,157		6,873	$	(8,552	)	$	(93,235	)	$	(129	)	$	(37,759	)

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	2014			2013			2012
Operating activities
Net loss including noncontrolling interest	$	(84,515	)	$	(240,199	)	$	(2,592	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		161,073			427,906			119,868
Deferred income taxes		(10,119	)		(127,484	)		21,652
Gain on extinguishment of Senior Secured Notes		(6,718	)		—			—
Stock-based compensation expense		12			1,043			—
Settlement of noncontrolling interest		624			—			—
Loss on sale or disposal of inventory		—			—			954
Changes in assets and liabilities:
Change in restricted cash		(13,750	)		—			—
Accounts and revenues receivable		10,152			7,630			4,049
Change in derivatives, net		(20,154	)		4,480			10,076
Accounts payable and accrued liabilities		14,982			15,432			(21,291	)
Revenues and severance taxes payable		(5,227	)		(6,888	)		(4,732	)
Interest payable on Senior Secured Notes		(375	)		1,563			—
Settlements of asset retirement obligations		(7,344	)		(4,606	)		(827	)
Other		3,666			(135	)		1,121

Net cash provided by operating activities		42,307			78,742			128,278
Investing activities
Change in advances from joint interest partners		(4,266	)		4,767			(934	)
Additions to oil and gas properties and equipment		(106,473	)		(126,320	)		(180,500	)
Purchase of reserves in place		(4,921	)		—			—
Proceeds from net sales of oil and gas properties		506			68,901			26,427

Net cash used in investing activities		(115,154	)		(52,652	)		(155,007	)
Financing activities
Proceeds from borrowings		88,944			6,757			7,101
Proceeds from revolving credit facility		—			—			50,000
Payments on borrowings		(5,883	)		(56,242	)		(7,204	)
Proceeds from issuance of 12.5% Senior Secured Notes due 2015		—			51,500			—
Purchases of 12.5% Senior Secured Notes due 2015		(5,220	)		—			—
Purchase of noncontrolling interest		(3,272	)		—			—
Payments of deferred financing costs		(2,941	)		(1,540	)		—
Purchase of treasury stock		—			(2,816	)		—
Payment of dividends		—			(1,562	)		(6,250	)
Other		8			—			10

Net cash provided by (used in) financing activities		71,636			(3,903	)		43,657

Increase (decrease) in cash and cash equivalents		(1,211	)		22,187			16,928
Cash and cash equivalents, beginning of period		90,858			68,671			51,743

Cash and cash equivalents, end of period	$	89,647		$	90,858		$	68,671

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 producing assets are mainly located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas and California.

2. Significant Accounting Policies

The financial statements included in this annual report have been prepared using the going concern assumption which contemplates continuity of operations, the realization of assets and satisfaction of liabilities and commitments in the ordinary course of business. The accompanying financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern. The Company has substantial debt due during 2015. Without access to additional liquidity, the Company will not be able to fund its commitments to the holders of the Senior Secured Notes or the lenders under the Term Loan Facility and will be in default under the Senior Secured Notes and Term Loan Facility. If these defaults occur, the Company will be unable to continue as a going concern. See Note 8, Debt for further discussion.

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 (“U.S. GAAP”). 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

Capitalized overhead costs amounted to $7.4 million, $8.2 million and $4.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company capitalized interest of $2.0 million, $2.4 million and $6.8 million during the years ended December 31, 2014, 2013 and 2012, respectively, related to significant properties not subject to amortization.

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 12, 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 Gains (losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in 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. Deferred tax assets are also recognized for the estimated future effects of tax losses or credit carryforwards. Valuation allowances are established when necessary on a jurisdictional basis to reduce deferred tax assets to the amounts expected to be realized. 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, 2014, 2013 and 2012 were not significant. Severance taxes incurred to governments were $7.5 million, $8.0 million and $9.3 million for 2014, 2013 and 2012, 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

In accordance with the provisions of FASB guidance related to accounting for asset retirement obligations and FASB guidance on accounting for conditional asset retirement obligations, costs associated with the retirement of fixed assets (e.g., oil and gas production facilities, etc.) that the Company is legally obligated to incur are accrued. The fair value of the obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the fixed asset and are depreciated over the life of the applicable asset. 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. See Note 5, Property, Plant and Equipment and Asset Retirement Obligations, for additional information.

Reclassifications

Certain prior year amounts have been reclassified in the accompanying consolidated financial statements to conform with the 2014 presentation. Such reclassifications are not material to the accompanying consolidated financial statements.

Operating Segments

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

Recently Issued Accounting Standards

In August 2014, the FASB issued ASU 2014-15: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern that will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU 2014-15 becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

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, 2014 and 2013, the Company’s commodity derivative contracts were recorded at fair value. The fair values of these instruments were measured using valuations based upon quoted prices for similar assets and liabilities in active markets (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 (in thousands):


	Fair Value Measurements Using
	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, 2014
Assets:
Commodity derivatives	$	—	$	21,132		$	—	$	21,132		$	(3,914	)	$	17,218
Liabilities:
Commodity derivatives		—		(3,914	)		—		(3,914	)		3,914			—
December 31, 2013
Assets:
Commodity derivatives	$	—	$	3,735		$	—	$	3,735		$	(2,194	)	$	1,541
Liabilities:
Commodity derivatives		—		(6,671	)		—		(6,671	)		2,194			(4,477	)

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

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


	Fair Value Measurements Using Significant Other Observable Inputs (Level 2)
Description	December 31, 2014		December 31, 2013
Assets:
Fair value of commodity derivatives - current assets	$	11,753	$	—
Fair value of commodity derivatives - long-term assets		5,465		1,541

Total Assets	$	17,218	$	1,541

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

Total Liabilities	$	—	$	(4,477	)

During September 2010, July 2011 and April 2013, the Company issued Senior Secured Notes. At December 31, 2014, the fair value of the Notes was estimated to be $102.3 million, based on the prices the bonds have recently been quoted at in the market, which represent Level 2 inputs. As of December 31, 2014, a total of $238.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $238.4 million as of December 31, 2014. The Company repurchased $12.0 million of the Notes in December 2014. See Note 8, Debt, for additional information.

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.

The carrying value of cash and cash equivalents, restricted cash, accounts receivable, revenues receivable, accounts payable, and revenues payable approximate fair value because of the short-term maturity of those instruments. Borrowings under the Term Loan Facility (as defined in Note 8) are at variable interest rates and accordingly their carrying amounts approximate fair value.

4. Accounts and Revenues Receivable

Accounts and revenues receivable at December 31, 2014 and 2013 were $14.3 million and $25.0 million, respectively, all of which were due from companies in the oil and gas industry. Of the revenues receivable, $9.8 million was due from five companies and $16.5 million was due from five companies at December 31, 2014 and December 31, 2013, respectively.

Since all of the Company’s accounts receivable from purchasers and joint interest owners at December 31, 2014 and December 31, 2013 resulted from sales of crude oil, condensate, natural gas and/or joint interest billings to third-party companies in the oil and gas industry, this concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that allowances for doubtful accounts were adequate to absorb estimated losses as of December 31, 2014 and December 31, 2013. 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, 2014, 2013 and 2012 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.


	2014			2013			2012
Company A		29	%		32	%		35	%
Company B		21	%		21	%		17	%
Company C		20	%		11	%		(a	)
Company D		13	%		16	%		14	%
Company E		(a	)		(a	)		10	%

(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, 2014 and 2013 (in thousands):


	December 31,
	2014			2013
Oil and natural gas properties (full cost method):
Properties being amortized	$	1,560,739		$	1,432,310
Properties not subject to amortization		27,928			45,752

Total oil and natural gas properties		1,588,667			1,478,062
Less accumulated depreciation, depletion and amortization		(1,346,567	)		(1,190,944	)

Net oil and gas properties		242,100			287,118

Land		1,025			1,025
Buildings and improvements		6,492			6,492
Office equipment and software		6,901			6,246
Leased equipment		345			345
Furniture and fixtures		830			830

Total		15,593			14,938
Less accumulated depreciation		(9,210	)		(7,686	)

Net capitalized costs		6,383			7,252

Capitalized assets, net	$	248,483		$	294,370

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 2014 resulted in a $82.8 million write-down and was based on twelve-month average prices of $91.48 per barrel of oil, plus adjustments by lease for quality, transportation fees, and regional price differentials and $4.35 per MMBtu of natural gas, plus adjustments by lease for energy content, transportation fees, and regional price differentials. At September 30, 2014, the Company’s ceiling test computation resulted in a $0.4 million write-down and was based on the trailing 12-month average prices of $95.56 per barrel of oil plus adjustments by lease for quality, transportation fees, and regional price differentials and $4.24 per MMBtu of natural gas plus adjustments by lease for energy content, transportation fees, and regional price differentials. At June 30, 2014, the Company’s ceiling test computation resulted in a $5.3 million write-down and was based on the trailing 12-month average prices of $96.75 per barrel of oil plus adjustments by lease for quality, transportation fees, and regional price differentials and $4.10 per MMBtu of natural gas plus adjustments by lease for energy content, transportation fees, and regional price differentials. These write-downs were recorded in Depreciation, depletion and amortization in the consolidated statement of operations. 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.

Purchase of Oil and Gas Properties

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

During the second quarter of 2014, the Company entered into an agreement to purchase all of the issued and outstanding equity of Charter V, Inc. (“Charter V”) from the shareholders (the “Sellers”) of Charter V for a net purchase price of approximately $5.9 million. The aggregate consideration was based upon a Charter V reserve report from independent reserve engineers. The purchase was approved by the Company’s Board of Directors. Charter V held reserves totaling 0.4 MBOE. The Sellers consist of 46 individuals who were employees of the Company and Century Exploration New Orleans, LLC, a subsidiary of the Company, as of December 31, 2010. Among these individuals are Howard A. Settle, Chief Executive Officer and a Director of the Company, Jeff T. Craycraft, Chief Financial Officer, and Michael J. Willis, Senior Vice President and a Director of the Company. Prior to the transaction, Charter V was a consolidated variable interest entity (“VIE”) of the Company. The Company completed the purchase on July 2, 2014. See Note 11, Variable Interest Entities, for additional information.

Sales 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 on the accompanying consolidated balance sheets, 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 also received a $17.3 million net carry from this unrelated third party. The sale was recorded as a reduction to our net oil and gas properties on the accompanying 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.

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 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 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.

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, 2013	$	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
Accretion expense		1,406
Additions		466
Settlement of ARO		(7,344	)
Changes in ARO estimate		6,859

Balance of ARO as of December 31, 2014	$	44,614

The change in estimate during 2014 is due to new information the Company received through quotes from third parties in regard to performing plugging and abandonment work on some of the Company’s properties located in Federal waters. ARO estimates also increased on certain previously existing platforms and facilities in state waters as a result of additional development.

The change in estimate during 2013 was 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.

The Company pre-funded $13.8 million for plugging and abandonment work expected to be performed during 2015. This balance is in an escrow account and is recorded as Restricted cash on the accompanying consolidated balance sheets.

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. As required by the Fifth Amended and Restated Credit Agreement (as defined in Note 8), the Company’s derivative counterparties are limited to our secured lenders, which helps to minimize any potential non-performance risk.

With respect to any collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction. For any particular floor contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor contract.

All of the Company’s commodity derivative transactions are settled based on reported settlement prices on the 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 Gains (losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in Gains (losses) on derivatives, net in the accompanying consolidated statements of operations.

At December 31, 2014, $17.2 million represented the fair value of the commodity derivatives. This $17.2 million was made up of approximately $11.7 million in current assets and $5.5 million in long-term assets. 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.

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


Remaining Contract Term	Contract Type	Volume in MMBtus/ Month		NYMEX Strike Price
January 2015 - March 2015	Swap		212,973	$	4.09
January 2015 - December 2015	Swap		375,806	$	4.01
January 2015 - December 2015	Put - Sell		316,430	$	3.50
January 2016	Swap		81,354	$	4.02
January 2016 - March 2016	Swap		120,675	$	4.10
January 2016 - December 2016	Put - Buy		240,397	$	4.00
January 2016 - December 2016	Put - Sell		240,397	$	3.50
January 2016 - December 2016	Call - Sell		240,397	$	4.73

As of December 31, 2014, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast oil production for 2015 and 2016:


Remaining Contract Term	Contract Type		Volume in BBls/ Month		NYMEX Strike Price
January 2015 - December 2015		Swap		22,338	$	89.44
January 2016 - December 2016		Swap		15,335	$	88.12

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

7. Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following at December 31, 2014 and 2013 (in thousands):


	December 31,
	2014		2013
Accounts payable	$	22,662	$	20,141
Oil and gas property costs accrual		10,023		2,691
Production and delivery costs accrual		1,356		2,233
Compensation and benefits accrual		1,038		2,408
Other		645		593

Total Accounts payable and Accrued liabilities	$	35,724	$	28,066

8. Debt

Going Concern

The financial statements included in this annual report have been prepared using the going concern assumption which contemplates continuity of operations, the realization of assets and satisfaction of liabilities and commitments in the ordinary course of business. The accompanying financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern. The Company has substantial debt due during 2015, including $238.0 million of Senior Secured Notes due October 1, 2015 and $85.0 million under the Term Loan Facility due July 2, 2015, if the Senior Secured Notes have not been refinanced by this date. The $85.0 million under the Term Loan Facility is not due until September 12, 2016, if the Senior Secured Notes are refinanced prior to July 2, 2015. Accordingly, the outstanding amounts of Senior Secured Notes and the Term Loan Facility have been classified as current liabilities.

Additionally, we will not make our scheduled interest payment to the holders of the Senior Secured Notes due on April 1, 2015. However, under the terms of the indenture for the Senior Secured Notes, there is a 30-day grace period during which we could elect to make the interest payment and cure any potential event of default for non-payment. Absent payment of the interest by the end of the cure window on May 1, 2015, we will be in default under the indenture for the Senior Secured Notes, which will result in the acceleration of our obligation to repay all principal and interest due under the Senior Secured Notes.

Without access to additional liquidity, the Company will not be able to fund its commitments, including the April 1, 2015 interest payment, to the holders of the Senior Secured Notes or the lenders under the Term Loan Facility and will be in default under the Senior Secured Notes and the Term Loan Facility. If these defaults occur, the Company will be unable to continue as a going concern.

As of December 31, 2014, the Company had $89.6 million in cash and cash equivalents, as well as $13.8 million of restricted cash in escrow for plugging and abandonment work. Over the next six months, the Company intends to fund general and administrative expenses, interest payments, and capital expenditures from cash on hand and cash flows from operations.

These matters raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s Board of Directors and executive management have detailed drilling programs in place in our core areas to increase production and reserves and lead to future drilling opportunities in these areas. The Company is actively working with investment banking advisors and intends to access the capital markets by issuing debt and/or equity securities. No assurance can be given that such financing will be available on terms that are acceptable to the Company, or at all.

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 Secured Notes due 2015 (the “Additional 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 “Senior Secured 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 previous 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 Senior Secured Notes are guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our Term Loan Facility. The Senior Secured Notes and the guarantees are secured by a security interest in substantially all of our existing and future domestic subsidiaries’ (other than certain future unrestricted subsidiaries’) assets to the extent they constitute collateral under our Term Loan Facility, subject to certain exceptions. Pursuant to an intercreditor agreement, dated September 24, 2010, the lien securing the notes is subordinated and junior to liens securing our Term Loan Facility.

The Senior Secured 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 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 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 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 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 Senior Secured Notes at December 31, 2014.

In December 2014, the Company repurchased $12.0 million of the Senior Secured Notes at 43.5% of their face amount. The Company recognized a $6.7 million gain on this repurchase which is recorded in Gain on extinguishment of Senior Secured Notes in the accompanying consolidated statement of operations. The carrying amount of the Senior Secured Notes was $238.4 million as of December 31, 2014. The carrying amount of the Senior Secured Notes was $251.0 million as of December 31, 2013.

The Company is actively working with investment banking advisors to refinance the Senior Secured Notes in 2015. In conjunction with these advisors, the Company has developed and is executing a robust drilling program. The Company is focused on drilling and increasing reserves in two core areas in the shallow waters of the Gulf of Mexico prior to the anticipated refinancing. The Company believes that the addition of these wells will increase production and reserves and will lead to future drilling opportunities in these core areas. As discussed in the Going Concern section above, no assurance can be given that such financing will be available on terms that are acceptable to the Company, or at all.

Term Loan Facility

The proceeds of the term loan incurred under the Fifth Amended and Restated Credit Agreement were or will be used to (a) repay all expenses, fees or indemnitees outstanding under the Fourth Amended and Restated Credit Agreement dated as of November 29, 2011, (b) finance capital expenditures associated with the Company’s oil and gas properties, (c) provide working capital for the Company’s operations and (d) pay transaction fees and expenses incurred in connection with the transactions contemplated by the Fifth Amended and Restated Credit Agreement. The Fifth Amended and Restated Credit Agreement contains customary restrictions on, among other things the Company’s ability to incur debt, grant liens on their property, make dispositions or investments, enter into mergers or issue new securities, make distributions, enter into affiliate transactions, enter into hedging contracts, amend their organizational documents and create new subsidiaries. In addition, the Fifth Amended and Restated Credit Agreement requires the Company to maintain the following financial covenants as defined in the agreement: (i) a minimum Current Ratio of 1.0:1.0 as of the end of each fiscal quarter, (ii) a maximum First Lien Leverage Ratio of 2.0:1.0 as of the end of each fiscal quarter for the four immediately preceding fiscal quarters and (iii) a minimum PDP Asset Coverage Ratio of 1.0:1.0 as of January 1, 2015 and 1.1:1.0 as of April 1, 2015, July 1, 2015, January 1, 2016 and July 1, 2016. As of December 31, 2014, the Company was in compliance with all of these financial covenants.

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 $2.4 million at December 31, 2014 and $2.6 million at December 31, 2013. 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, 2014 and 2013.

Finance Agreement

During May 2014, the Company entered into an agreement to finance the premiums for its annual insurance policies. At December 31, 2014, $1.2 million was outstanding under this agreement. The finance agreement requires monthly installments of principal and interest in the amount of approximately $0.4 million until April 1, 2015. There are no covenant requirements under this agreement. The effective interest rate on this agreement was 2.39% at December 31, 2014. 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 required 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.

Long-term Debt Maturities

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


Year ending December 31:
2015	$	324,375
2016		170
2017		182
2018		195
2019		209
Thereafter		1,535

Total	$	326,666

Cash payments for interest net of amounts capitalized totaled $32.2 million, $26.4 million, and $18.6 million for the years ended December 31, 2014, 2013, and 2012, respectively.

9. Income Taxes

Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows (in thousands):


	December 31,
	2014			2013
Deferred tax assets:
Asset retirement obligation	$	15,648		$	15,479
Net operating loss carryforward		46,582			6,606
Percentage depletion carryforward		1,972			1,733
AMT credit carryforward		4,641			4,641
Other		—			833

Total deferred tax assets		68,843			29,292
Valuation allowance⁽¹⁾		(27,546	)		(4,081	)

Total deferred tax assets	$	41,297		$	25,211

Deferred tax liabilities:
Property, plant and equipment	$	(34,623	)	$	(34,266	)
Commodity derivatives		(6,778	)		(887	)
Other		(17	)		(298	)

Total deferred tax liabilities	$	(41,418	)	$	(35,451	)

⁽¹⁾	The valuation allowance primarily relates to the uncertainty surrounding our ability to realize recorded tax benefits on certain net operating loss and tax credit carryforwards, as well as percentage depletion.


	December 31,
	2014			2013
Current assets	$	—		$	3,938
Long term assets		1,712			—
Current liabilities		(1,833	)		—
Long term liabilities		—			(14,178	)

	$	(121	)	$	(10,240	)

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


	2014			2013			2012
Current income tax expense (benefit):
Federal	$	(403	)	$	(6,681	)	$	(21,697	)
State and local		(155	)		84			(1,751	)

	$	(558	)	$	(6,597	)	$	(23,448	)

Deferred income tax expense (benefit):
Federal	$	(10,319	)	$	(117,577	)	$	20,049
State and local		200			(9,906	)		1,603

	$	(10,119	)	$	(127,483	)	$	21,652

Total income tax provision	$	(10,677	)	$	(134,080	)	$	(1,796	)

We received net income tax refunds of $0.9 million in 2014 compared to net income tax refunds of $7.6 million in 2013 and net income tax refunds of $23.8 million in 2012.

The Company’s 2014, 2013 and 2012 effective tax rates are 11.2%, 35.8% and 40.9%, respectively, and are comprised of the following:


	2014			2013			2012
Statutory federal income tax rate		34.0	%		35.0	%		35.0	%
State and local taxes, net of federal benefit		1.9	%		1.9	%		9.6	%
Deferred rate change		0.5	%		0.5	%		0.9	%
Depletion in excess of basis		0.2	%		0.2	%		15.0	%
Section 199 deduction		0.0	%		0.0	%		1.7	%
Change in valuation allowance		-24.7	%		-1.1	%		0.0	%
Return to provision true-up		-0.1	%		-0.1	%		-20.6	%
Accounting method changes		-0.5	%		0.0	%		0.0	%
Other		-0.1	%		-0.6	%		-0.7	%

		11.2	%		35.8	%		40.9	%

The decrease in our effective tax rate from 2014 to 2013 was primarily due to the recording of additional valuation allowance to the extent deferred tax benefits cannot be realized through the reversal of existing taxable temporary difference and the recording of tax impacts from various applications for change in tax accounting methods filed during the fourth quarter of 2014.

In accordance with Accounting Standards Codification (“ASC”) Topic 740, Accounting for Income Taxes, the Company has determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that a portion of the deferred tax assets at December 31, 2014 will not be realized. Hence, deferred tax benefits were reserved through a valuation allowance recorded as part of the effective tax rate.

As of December 31, 2014, the Company had alternative minimum tax credit carryforwards of $4.6 million. The Company had percentage depletion carryforwards of $5.6 million. The Company also had net operating loss (NOL) carryforwards of $118.3 million and $131.7 million for federal and state reporting purposes, respectively.

The federal NOL carryforwards begin expiring in 2028, and the majority of the state NOL carryforwards begin expiring after 2021.

All of the Company’s income before taxes came from domestic operations. The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. The Company is subject to U.S. federal income tax examinations by tax authorities for periods after December 31, 2010 and U.S. state income tax examinations by tax authorities for periods after December 31, 2009.

U.S. GAAP prescribes a recognition threshold and measurement attribute for the accounting and financial statement disclosure of tax positions taken or expected to be taken in a tax return. The evaluation of a tax position is a two-step process. The first step requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination based on the technical merits of the position. The second step requires the Company to recognize in the financial statements each tax position that meets the more likely than not criteria, measured at the amount of benefit that has a greater than 50% likelihood of being realized. The Company had no uncertain tax positions at December 31, 2014. The $0.3 million of unrecognized tax benefits recorded at December 31, 2013 was released as a result of filing the application for change in accounting method.

A reconciliation of the total beginning and ending amounts of unrecognized tax benefits is as follows (in thousands):


	2014			2013		2012
Balances at January 1	$	298		$	—	$	—
Increases/(decreases) in unrecognized tax positions taken during the prior period		(298	)		298		—

Balance at December 31	$	—		$	298	$	—

10. Shareholders’ Equity

During January 2014, the Company issued 8 shares of common stock to one employee as compensation for services performed. The fair value of the shares at the date of issuance of approximately $12,000 was recorded as a credit to Common stock and a debit to General and administrative expenses in the consolidated statement of operations. During December 2013, the Company issued 632 shares of common stock to 26 employees as compensation for services performed. The fair value of the shares at the date of issuance of approximately $1.0 million was recorded as a credit to Common stock and a debit to General and administrative expenses and Oil and gas properties, for those employees that are directly involved in the acquisition, exploration and development of oil and gas reserves, in the consolidated statement of operations. The Company did not issue any shares during 2012.

The Company did not repurchase any shares during the year ended December 31, 2014. The Company repurchased 1,707 shares of common stock during 2013 for approximately $2.8 million. The Company did not repurchase any shares during the year ended December 31, 2012.

During 2014, there were no dividends paid. During 2013, dividends were paid at $25.00 per share to shareholders of record 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.

11. Variable Interest Entities

Certain related party entities known as the Charter entities have been consolidated in the Company’s financial statements in accordance with FASB accounting guidance related to Variable Interest Entities. The Charter entities were established as C-corporations to maintain a joint interest in certain wells owned and operated by the Company.

Certain employees and executive officers of the Company were provided an opportunity to purchase a number of shares of the applicable Charter entity based upon rank and tenure with the Company for $1 per share. The purpose of the establishment of these entities was to provide the employees with an opportunity to share in the success of the Company through the joint interest in the properties owned by the Charter entities. The first of these entities, Charter II, was established in 2006 followed by Charter III in 2008, Charter IV in 2009, and Charter V in 2010. The Company purchased Charter II in 2009, Charter III in 2011 and Charter V in 2014.

In performing an analysis of these entities for consolidation, the Company reviewed the guidance contained in FIN 46R, Consolidation of Variable Interest Entities, the accounting guidance in place at the time these entities were established, as well as the guidance contained in FAS 167, Amendments to FASB Interpretation No. 46R, now codified in ASC 810, Consolidation. The Company considered the following facts in this analysis:

•

The employee owners contributed minimal funds ($1 per share) as an initial capital investment in each of the respective Charter entities and become the legal owner of the applicable shares of Charter stock. There are no vesting provisions. Accordingly, the Charter entities were not funded with sufficient equity to fund their operations without sufficient additional financial support from RAAM.

•

The Company requires no initial investment from the Charter entities to acquire the joint interest in the properties. Payables incurred by Charter to RAAM for costs incurred in developing the wells are not required to be paid until revenues are generated from the properties at which time they are deducted from the joint interest billings due from the Charter entity. In addition, the employee owners have no obligation to invest additional funds should the wells not produce sufficient revenues to cover the costs. Accordingly, RAAM assumes all of the risk if the wells are dry or do not produce sufficient revenues to offset the costs incurred to develop the properties and fund the operation of the wells.

•

The Board of Directors of the Charter entities are comprised of members of senior management of RAAM. While the employee owners have voting rights to elect the Directors of Charter they have no rights to vote on key operating or management decisions, including sale or disposition of entity. Since the shareholders of the Charter entities are employees of RAAM and all key decisions are made by the Board of Directors of the Charter entities their voting rights are not considered substantive.

•

Upon termination or retirement from the Company, RAAM has the option to purchase the shares from the employee; however, there is no obligation to do so. In addition, the employees are not required to sell or assign their shares to any party upon termination or retirement from RAAM. They are permitted to hold on to their Charter shares in those instances.

Given the conclusion regarding consolidation noted above, the issuance of the Charter shares to employees represents the issuance of shares of a consolidated subsidiary to employees qualifying for consideration as compensation costs in accordance with ASC Topic 718, Compensation-Stock Compensation (ASC 718).

In consideration of this guidance, the Company performed an analysis of the value of these entities at the date of share issuances. This analysis was performed in order to determine RAAM’s compensation cost, which would be equal to the amount the fair value of the Charter shares exceeds the purchase price. Generally speaking, at inception, the Charter entities have minimal fair value as the properties are in the early stages of being established and there is much uncertainty regarding the drilling prospects (i.e. dry well vs. active producing well). As a result, the estimated value of the reserves do not surpass the amount of the payable to RAAM until later in the drilling stage of the various wells when more certainty exists regarding the future reserve prospects. Accordingly, no compensation expense has been recognized in the consolidated financial statements.

During the second quarter of 2014, the Company entered into an agreement to purchase all of the issued and outstanding equity of Charter V from the Sellers of Charter V for a net purchase price of approximately $5.9 million. The aggregate consideration was based upon a Charter V reserve report from independent reserve engineers. The purchase was approved by the Company’s Board of Directors. Charter V held reserves totaling 0.4 MBOE. The Sellers consist of 46 individuals who were employees of the Company and Century Exploration New Orleans, LLC, a subsidiary of the Company, as of December 31, 2010. Among these individuals are Howard A. Settle, Chief Executive Officer and a Director of the Company, Jeff T. Craycraft, Chief Financial Officer, and Michael J. Willis, Senior Vice President and a Director of the Company. The Company completed the purchase on July 2, 2014.

As of December 31, 2014, 2013 and 2012, Charter IV has been consolidated in the financial statements. Financial information for Charter IV can be found in Note 14, Condensed Consolidating Financial Information in the Non-guarantor VIEs column.

12. Related Party Transactions

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. Amounts due from such related parties of approximately $8,000 and $1.1 million at December 31, 2014 and 2013 are included in Accounts receivable in the Company’s consolidated balance sheets and represent joint interest owner receivables. Amounts due to such related parties of $0.1 million and $2.0 million at December 31, 2014 and 2013, respectively, are included in Revenues and severance taxes payable in the Company’s consolidated balance sheets and represent revenue owner payables.

A related party entity owned 100% by a majority shareholder was previously a working interest and revenue partner in certain of the Company’s properties. During the second quarter of 2014, the Company purchased this related party’s working interests in 19 wells located onshore Texas that represented 0.5 MBOE of reserves for a net purchase price of $4.9 million. The Company obtained a reserve report from independent reserve engineers, which was used to help determine the purchase price. The purchase was approved by the Company’s Board of Directors. The company considers pro-forma information related to the purchase of these reserves to be nominal. At December 31, 2013, this related party owed the Company approximately $1.1 million, which was included in Accounts receivable in the Company’s consolidated balance sheets, and represent joint interest owner receivables. Revenues owed to the entity at December 31, 2013 totaled $0.9 million, are included in Revenues and severance taxes payable in the Company’s consolidated balance sheets, and represent revenue owner payables.

Beginning in May 2002, the Lexington office space was leased from a related party entity owned 100% by a majority shareholder of the Company; total rent expense was approximately $228,000, $223,000 and $218,000, during 2014, 2013 and 2012, respectively. See Note 13, Commitments and Contingencies for further information.

13. Commitments and Contingencies

The Company leases office space for its Lexington, Kentucky, New Orleans, Louisiana, and Bakersfield, California offices under operating leases expiring in various years through 2016. The Lexington, Kentucky office space is leased from a related party (see Note 12, Related-Party Transactions). At December 31, 2014, future minimum rental payments required under these leases are as follows (in thousands):


Year ending December 31:	Minimum Lease Payments
2015		569
2016		140

Total	$	709

Rent expense under operating leases was approximately $672,000, $684,000, and $747,000 for 2014, 2013 and 2012, respectively.

Historically, the majority of the Company’s proved oil and gas properties have been located in the Gulf of Mexico, resulting in a concentration of its operations in one geographic area. Management has concentrated its efforts since 1996 in developing prospects in other geographic areas in order to mitigate this risk. During 2014 and 2013, the Company drilled successful wells onshore and has developed additional onshore drilling prospects that are anticipated to be drilled during 2015.

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

14. Condensed Consolidating Financial Information

The following condensed consolidating financial information is presented in accordance with SEC regulation S-X requirements relating to multiple subsidiary guarantors of securities issued by the parent company of those subsidiaries. During 2010, RAAM Global issued the Senior Secured Notes, described in Note 8, Debt. Each of RAAM Global’s wholly owned subsidiaries are guarantors of these notes. The guarantees are full and unconditional and joint and several.

The following tables present condensed consolidating balance sheets as of December 31, 2014 and 2013, condensed consolidating statements of operations for the years ended December 31, 2014, 2013 and 2012, and condensed consolidating statements of cash flows for the years ended December 31, 2014, 2013 and 2012, and should be read in conjunction with the consolidated financial statements herein.

Condensed Consolidating Balance Sheets

At December 31, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors		Non-guarantor VIE			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	760		$	88,887	$	—		$	—		$	89,647
Restricted Cash		—			13,750		—			—			13,750
Receivables, net		—			18,485		—			(4,154	)		14,331
Commodity derivatives		—			11,753		—			—			11,753
Prepaids and other current assets		3,441			2,901		—			—			6,342

Total current assets		4,201			135,776		—			(4,154	)		135,823

Net oil and gas properties		—			238,075		4,025			—			242,100
Other assets:
Other capitalized assets, net		6,079			304		—			—			6,383
Commodity derivatives		—			5,465		—			—			5,465
Investment in affiliates		202,280			—		—			(202,280	)		—
Other		20			1,835		—			—			1,855

Total other assets		208,379			7,604		—			(202,280	)		13,703

Total assets	$	212,580		$	381,455	$	4,025		$	(206,434	)	$	391,626

Liabilities and equity
Current liabilities:
Payables and accrued liabilities	$	9,191		$	46,443	$	4,154		$	(4,154	)	$	55,634
Advances from joint interest partners		—			586		—			—			586
Asset retirement obligations		—			14,525		—			—			14,525
Senior secured notes		238,425			—		—			—			238,425
Debt		145			85,699		—			—			85,844
Deferred income taxes		—			1,833		—			—			1,833

Total current liabilities		247,761			149,086		4,154			(4,154	)		396,847

Other liabilities:
Asset retirement obligations		—			30,089		—			—			30,089
Long-term debt		2,290			—		—			—			2,290
Other long-term liabilities		159			—		—			—			159

Total other liabilities		2,449			30,089		—			—			32,538
Total liabilities		250,210			179,175		4,154			(4,154	)		429,385
Equity attributable to RAAM Global shareholders		(37,630	)		202,280		—			(202,280	)		(37,630	)
Noncontrolling interest		—			—		(129	)		—			(129	)

Total equity		(37,630	)		202,280		(129	)		(202,280	)		(37,759	)

Total liabilities and equity	$	212,580		$	381,455	$	4,025		$	(206,434	)	$	391,626

Condensed Consolidating Balance Sheets

At December 31, 2013 (in thousands)


	RAAM Global Energy Company		Subsidiary Guarantors		Non-guarantor VIEs		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	628	$	90,225	$	5	$	—		$	90,858
Receivables, net		—		33,124		823		(8,958	)		24,989
Deferred tax asset		—		3,938		—		—			3,938
Prepaids and other current assets		3,068		5,898		—		—			8,966

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

Net oil and gas properties		4,112		271,459		11,547		—			287,118
Other assets:
Other capitalized assets, net		7,047		205		—		—			7,252
Commodity derivatives		—		1,541		—		—			1,541
Investment in affiliates		301,122		—		—		(301,122	)		—
Other		1,730		220		—		—			1,950

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

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

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

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

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

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

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

Condensed Consolidating Statements of Operations

For the year ended December 31, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations		Consolidated
Revenues:
Gas sales	$	—		$	58,775		$	1,647		$	—	$	60,422
Oil sales		—			66,525			1,133			—		67,658
Gains on derivatives, net		—			15,056			—			—		15,056

Total revenues		—			140,356			2,780			—		143,136
Costs and expenses:
Production and delivery costs		—			27,165			174			—		27,339
Production taxes		—			7,296			172			—		7,468
Workover costs		—			2,143			—			—		2,143
Depreciation, depletion and amortization		341			156,303			1,420			—		158,064
General and administrative expenses		9,730			4,696			8			—		14,434

Total operating expense		10,071			197,603			1,774			—		209,448

Income (loss) from operations		(10,071	)		(57,247	)		1,006			—		(66,312	)
Other income (expenses):
Interest expense, net		(31,998	)		(2,640	)		—			—		(34,638	)
Gain on extinguishment of senior secured notes		6,718			—			—			—		6,718
Loss from equity investment in subsidiaries		(51,318	)		—			—			51,318		—
Other, net		308			(1,268	)		—			—		(960	)

Total other income (expenses)		(76,290	)		(3,908	)		—			51,318		(28,880	)

Income (loss) before taxes		(86,361	)		(61,155	)		1,006			51,318		(95,192	)
Income tax benefit		(567	)		(9,837	)		(273	)		—		(10,677	)

Net income (loss) including noncontrolling interest	$	(85,794	)	$	(51,318	)	$	1,279		$	51,318	$	(84,515	)

Net income attributable to noncontrolling interest (net of tax)		—			—			1,279			—		1,279

Net income (loss) attributable to RAAM Global	$	(85,794	)	$	(51,318	)	$	—		$	51,318	$	(85,794	)

Condensed Consolidating Statements of Operations

For the year ended December 31, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations		Consolidated
Revenues:
Gas sales	$	—		$	59,803		$	3,150	$	—	$	62,953
Oil sales		—			88,292			3,326		—		91,618
Losses on derivatives, net		—			(5,038	)		—		—		(5,038	)

Total revenues		—			143,057			6,476		—		149,533
Costs and expenses:
Production and delivery costs		—			34,456			547		—		35,003
Production taxes		—			7,670			295		—		7,965
Workover costs		—			3,697			32		—		3,729
Depreciation, depletion and amortization		828			421,940			3,293		—		426,061
General & administrative expenses		10,710			10,644			5		—		21,359

Total operating expense		11,538			478,407			4,172		—		494,117

Income (loss) from operations		(11,538	)		(335,350	)		2,304		—		(344,584	)
Other income (expenses):
Interest expense, net		(29,008	)		(561	)		—		—		(29,569	)
Loss from equity investment in subsidiaries		(207,343	)		—			—		207,343		—
Other, net		(150	)		24			—		—		(126	)

Total other income (expenses)		(236,501	)		(537	)		—		207,343		(29,695	)

Income (loss) before taxes		(248,039	)		(335,887	)		2,304		207,343		(374,279	)
Income tax provision (benefit)		(6,622	)		(128,544	)		1,086		—		(134,080	)

Net income (loss) including noncontrolling interest	$	(241,417	)	$	(207,343	)	$	1,218	$	207,343	$	(240,199	)

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

Net income (loss) attributable to RAAM Global	$	(241,417	)	$	(207,343	)	$	—	$	207,343	$	(241,417	)

Condensed Consolidating Statements of Operations

For the year ended December 31, 2012 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations			Consolidated
Revenues:
Gas sales	$	—		$	61,619		$	1,916	$	—		$	63,535
Oil sales		—			116,591			2,913		—			119,504
Gains on derivatives, net		—			20,769			—		—			20,769

Total revenues		—			198,979			4,829		—			203,808
Costs and expenses:
Production and delivery costs		—			35,098			431		—			35,529
Production taxes		—			9,100			214		—			9,314
Workover costs		—			2,762			10		—			2,772
Depreciation, depletion and amortization		304			115,278			2,459		—			118,041
General & administrative expenses		5,106			15,667			7		—			20,780

Total operating expense		5,410			177,905			3,121		—			186,436

Income (loss) from operations		(5,410	)		21,074			1,708		—			17,372
Other income (expenses):
Interest expense, net		(19,304	)		(1,933	)		—		—			(21,237	)
Loss on disposals of inventory		—			(954	)		—		—			(954	)
Income from equity investment in subsidiaries and VIEs		246			—			—		(246	)		—
Other, net		376			55			—		—			431

Total other income (expenses)		(18,682	)		(2,832	)		—		(246	)		(21,760	)

Income (loss) before taxes		(24,092	)		18,242			1,708		(246	)		(4,388	)
Income tax provision (benefit)		(21,500	)		19,310			394		—			(1,796	)

Net income (loss) including noncontrolling interest	$	(2,592	)	$	(1,068	)	$	1,314	$	(246	)	$	(2,592	)

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

Net income (loss) attributable to RAAM Global	$	(3,906	)	$	(1,068	)	$	1,314	$	(246	)	$	(3,906	)

Condensed Consolidating Statements of Cash Flows

For the year ended December 31, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(90,702	)	$	79,281		$	2,410		$	51,318		$	42,307
Investing activities
Change in investments between affiliates		101,788			(48,726	)		(1,744	)		(51,318	)		—
Change in advances from joint interest partners		—			(4,266	)		—			—			(4,266	)
Additions to oil and gas properties and equipment		(92	)		(105,709	)		(672	)		—			(106,473	)
Purchase of reserves in place		—			(4,921	)		—			—			(4,921	)
Proceeds from net sales of oil and gas properties		—			506			—			—			506

Net cash provided by (used in) investing activities		101,696			(163,116	)		(2,416	)		(51,318	)		(115,154	)
Financing activities
Proceeds from borrowings		—			88,944			—			—			88,944
Payments on borrowings		(160	)		(5,723	)		—			—			(5,883	)
Purchase of 12.5% Senior Secured Notes due 2015		(5,220	)		—			—			—			(5,220	)
Purchase of noncontrolling interest		(3,272	)		—			—			—			(3,272	)
Deferred loan costs		(2,210	)		(731	)		—			—			(2,941	)
Other		—			7			1			—			8

Net cash provided by (used in) financing activities		(10,862	)		82,497			1			—			71,636

Increase (decrease) in cash and cash equivalents		132			(1,338	)		(5	)		—			(1,211	)
Cash and cash equivalents, beginning of period		628			90,225			5			—			90,858

Cash and cash equivalents, end of period	$	760		$	88,887		$	—		$	—		$	89,647

Condensed Consolidating Statements of Cash Flows

For the year ended December 31, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(233,553	)	$	99,249		$	5,703		$	207,343		$	78,742
Investing activities
Change in investments between affiliates		193,550			17,908			(4,115	)		(207,343	)		—
Change in advances from joint interest partners		—			4,767			—			—			4,767
Additions to oil and gas properties and equipment		(5,339	)		(119,389	)		(1,592	)		—			(126,320	)
Proceeds from net sales of oil and gas properties		—			68,901			—			—			68,901

Net cash provided by (used in) investing activities		188,211			(27,813	)		(5,707	)		(207,343	)		(52,652	)
Financing activities
Proceeds from borrowings		—			6,757			—			—			6,757
Payments on borrowings		(126	)		(56,116	)		—			—			(56,242	)
Proceeds from issuance of 12.5% Senior Notes due 2015		51,500			—			—			—			51,500
Deferred bond costs		(1,540	)		—			—			—			(1,540	)
Purchase of treasury stock		(2,816	)		—			—			—			(2,816	)
Payment of dividends		(1,562	)		—			—			—			(1,562	)

Net cash provided by (used in) financing activities		45,456			(49,359	)		—			—			(3,903	)

Increase (decrease) in cash and cash equivalents		114			22,077			(4	)		—			22,187
Cash and cash equivalents, beginning of period		514			68,148			9			—			68,671

Cash and cash equivalents, end of period	$	628		$	90,225		$	5		$	—		$	90,858

Condensed Consolidating Statements of Cash Flows

For the year ended December 31, 2012 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	134		$	124,183		$	4,207		$	(246	)	$	128,278
Investing activities
Change in investments between affiliates		6,862			(7,108	)		—			246			—
Change in advances from joint interest partners		—			(934	)		—			—			(934	)
Additions to oil and gas properties and equipment		(443	)		(175,608	)		(4,449	)		—			(180,500	)
Proceeds from net sales of oil and gas properties		—			26,190			237			—			26,427

Net cash provided by (used in) investing activities		6,419			(157,460	)		(4,212	)		246			(155,007	)
Financing activities
Proceeds from revolving credit facility		—			50,000			—			—			50,000
Proceeds from borrowings		—			7,101			—			—			7,101
Payments on borrowings		(139	)		(7,065	)		—			—			(7,204	)
Payment of dividends		(6,250	)		—			—			—			(6,250	)
Other		10			—			—			—			10

Net cash (used in) provided by financing activities		(6,379	)		50,036			—			—			43,657

Increase (decrease) in cash and cash equivalents		174			16,759			(5	)		—			16,928
Cash and cash equivalents, beginning of period		340			51,389			14			—			51,743

Cash and cash equivalents, end of period	$	514		$	68,148		$	9		$	—		$	68,671

100

15. Supplemental Oil and Gas Data (Unaudited)

The supplemental information that follows shows estimates of the discounted future net cash flows from proved oil and gas reserves, changes in such estimates and various cost data. This information has been prepared in accordance with requirements prescribed by Statement of Financial Accounting Standards No. 69 (SFAS 69). SFAS 69 was codified into FASB ASC Topic 932, Extractive Activities – Oil and Gas. Inherent in the underlying calculations of such data are many variables and assumptions, the more significant of which are described below:

•

Estimates of all discounted future net cash flows from proved oil and gas reserves are primarily based on reports of independent petroleum engineers. Probable and possible reserves, a portion of which experience has indicated generally become proved once further exploration work has been conducted, are not considered.

•

Future net cash flows have been discounted at an annual rate of 10% and have been reduced by applicable estimates of future production, development and net abandonment costs, all of which are based on current costs.

•

The reserve estimates have been valued using the average of the first-day-of-the-month price for the 12-month period. Therefore, the value of the reserves is not an estimate of fair value. The prices received for oil and gas are subject to great variation and may increase or decrease according to market conditions.

In view of the uncertainties inherent in developing this supplemental data, it is emphasized that the information represents estimates of future net cash flows and caution should accompany its use and interpretation. In addition, this information should not be viewed as representative of the current value of the Company.

Costs Incurred (Unaudited)

The following represents the total costs incurred during 2014, 2013 and 2012 with respect to oil and gas producing activities (in thousands):


	2014		2013		2012
Costs incurred:
Unproved property	$	11,050	$	33,631	$	66,790
Proved property		4,921		—		—
Exploration costs		67,455		42,796		35,803
Development costs		20,330		43,733		73,374

Total costs incurred	$	103,756	$	120,160	$	175,967

101

Proved Oil and Gas Reserves (Unaudited)

The following sets forth estimates in proved and proved developed reserves of oil and gas and changes in estimates of proved reserves for 2014, 2013 and 2012. Oil, including condensate, is stated in barrels, and gas is stated in thousands of cubic feet at 14.73 P.S.I. All oil and gas reserves are located within the United States (in thousands):


	2014
	Oil			Gas
Beginning of year		3,703			42,129
Revisions of previous estimates		(1,048	)		(3,040	)
Production		(714	)		(12,490	)
Extensions and discoveries		830			6,981
Purchase of reserves in-place		61			2,818

Proved reserves end of year		2,832			36,398

Proved developed reserves at beginning of year		2,865			31,278
Proved developed reserves at end of year		2,832			36,398

	2013
	Oil			Gas
Beginning of year		14,707			62,022
Revisions of previous estimates		(9,826	)		(21,067	)
Production		(885	)		(14,859	)
Extensions and discoveries		595			16,033
Sale of reserves in-place		(888	)		—

Proved reserves end of year		3,703			42,129

Proved developed reserves at beginning of year		4,940			50,225
Proved developed reserves at end of year		2,865			31,278

	2012
	Oil			Gas
Beginning of year		12,949			63,059
Revisions of previous estimates		810			2,637
Production		(1,104	)		(18,411	)
Extensions and discoveries		2,052			14,737
Purchase of reserves in-place		—			—

Proved reserves end of year		14,707			62,022

Proved developed reserves at beginning of year		5,300			56,106
Proved developed reserves at end of year		4,940			50,225

102

Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves (Unaudited)

The Standardized measure of discounted future net cash flows from proved oil and gas reserves at 2014, 2013 and 2012 is as follows (in thousands):


	2014			2013			2012
Future cash flows	$	458,053		$	540,060		$	1,589,961
Future production costs		(158,820	)		(171,123	)		(403,363	)
Future development and abandonment costs		(55,863	)		(79,986	)		(242,189	)

Future net cash flows before income taxes and discount for timing		243,370			288,951			944,409
Future income taxes		(11,220	)		(50,320	)		(302,694	)
Discount for estimated timing of net cash flows		(48,709	)		(60,730	)		(276,935	)

Standardized measure of discounted future net cash flows	$	183,441		$	177,901		$	364,780

Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The primary sources of change in the standardized measure of discounted future net cash flows are as follows (in thousands):


	2014			2013			2012
Standardized measure of discounted future net cash flows from proved oil and gas reserves at beginning of year	$	177,901		$	364,780		$	424,052
Extensions and discoveries and improved recovery, net of future production and development costs		56,756			50,443			82,246
Purchase of reserves in-place		8,126			—			—
Sale of reserves in-place		—			(23,605	)		—
Development costs incurred during the period		20,330			43,733			73,374
Revenues, net of production costs		(100,741	)		(119,568	)		(147,510	)
Revisions of estimates:
Net change in prices		(5,877	)		(161,989	)		(27,003	)
Changes in estimated future development costs		5,768			99,249			(92,485	)
Revision of quantity estimates		(39,303	)		(297,329	)		39,075
Net change in income taxes		26,608			132,242			(5,817	)
Accretion of discount		22,822			66,747			68,954
Changes in production rates, timing and other		11,051			23,198			(50,106	)

Standardized measure of discounted future net cash flows from proved oil and gas reserves at end of year	$	183,441		$	177,901		$	364,780

103

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedure

We have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2014.

Changes in Internal Controls over Financial Reporting

There have been no changes in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of published financial statements in acceptance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that compliance with the policies or procedures may deteriorate or be circumvented.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on management’s assessment and the criteria established by COSO, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2014.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance


Name	Age	Title
Howard A. Settle	67	Chairman of the Board, Director, President, Chief Executive Officer
Jonathan B. Rudney	65	Director
Michael J. Willis	56	Sr. Vice President of Administration, Director
Thomas M. Lewry	69	Vice President, Director
Robert E. Fox	85	Director
Jeffrey T. Craycraft	58	Chief Financial Officer, Treasurer
Ken Young Elizabeth A. Barr	59 61	Chief Operating Officer Vice President of Administration

Set forth below is the description of the backgrounds of our directors, executive officers and other key employees.

Howard A. Settle. Howard A. Settle has served as our Chairman, Chief Executive Officer and President since 1986. Mr. Settle co-founded the predecessor of the Company in 1986. Mr. Settle has approximately 30 years of experience in the oil and gas industry. Mr. Settle received his undergraduate degree in accounting from the University of Kentucky, and prior to founding Century Oil Company, the predecessor of the Company, in 1982, he was a senior partner in the accounting firm of Settle and Holt, a certified public accounting firm. Mr. Settle was a co-founder of Century Oil Company. From 1982 to 1995 he served as the President, Chief Executive Officer, and Director of Century Oil Company, whose operations were located in the Appalachian basin and in the Illinois basin. In 1986, Mr. Settle was the co-founder of the predecessor of RAAM Global Energy Company, and has served as our Chairman, Chief Executive Officer, and President since 1986.

As co-founder of the Company, Mr. Settle is one of the driving forces behind the Company and its success to date. Over the course of the Company’s history, Mr. Settle has successfully grown the Company through his leadership skills and business judgment and for this reason we believe Mr. Settle is a valuable asset to our board.

Jonathan B. Rudney. Jonathan B. Rudney has served as a director of the Company since 2002. Mr. Rudney served as the President and Chief Executive Officer of Century Exploration Resources from 2011 through 2013. Mr. Rudney has approximately 30 years of executive experience in the various phases of the upstream oil and gas industry. Mr. Rudney co-founded the predecessor of the Company in 1986. During his tenure with the Company as an executive officer and director from 1986 to 1996, Mr. Rudney was responsible for overseeing exploration, production, construction, and engineering operations. Mr. Rudney structured and negotiated major bank financings and pioneered the development of innovative, non-traditional capital sources (e.g. volumetric production payments and natural gas swaps). Since departing the Company in 1996 as an officer, Mr. Rudney pursued personal oil and gas interests, both domestically and internationally. He has served as the President of Concordia Resources, LLC, a domestic investment vehicle, since 1997 as well as Chief Executive Officer of each of Century Exploration International, Inc. since 2004 and Concorde Energy, Inc. since 2010, both privately held international exploration and development companies. Mr. Rudney was reappointed to the Board of the Company in 2002 and presently serves in that capacity as an active member. Mr. Rudney holds a bachelor’s degree from the University of California at Santa Cruz.

As co-founder of the Company, Mr. Rudney, like Mr. Settle, is one of the driving forces behind the Company and its success to date. Mr. Rudney’s knowledge of the oil and gas business in many facets, his expertise in structuring and negotiating major bank financings and his development of innovative non-traditional capital sources have provided the Company with access to the capital it needs to continue to develop and acquire assets. For these reasons, we believe Mr. Rudney is well-qualified to serve on our board.

Michael J. Willis. Michael J. Willis has served as a Director of the Company since 1996. Mr. Willis currently serves as Senior Vice President of Administration. From 1996 until 2011, Mr. Willis served as our Chief Operating Officer.

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Mr. Willis has also served as the General Manager Century Exploration New Orleans since 2003. Mr. Willis joined the Company in 1992 and is currently a senior officer in the New Orleans, Louisiana office, heading up our exploration and operations management team. Prior to joining Century Exploration New Orleans, Mr. Willis served as the Vice President, Administration of Langlais, Ltd., Hong Kong from 1990 to 1992. Mr. Willis was an adjunct professor at the A.B. Freeman School of Business, Tulane University, where he taught a course in Business Information Systems from 1997 to 2005. Mr. Willis completed his Master of Business Administration A.B. Freeman School of Business, Tulane University and his undergraduate degree in accounting from the University of Cape Town, South Africa.

Mr. Willis brings extensive business and management expertise to the Company through his educational background and prior employment. Mr. Willis also provides the company with a perspective on the gulf coast that is unique to someone who lives in the area. For these reasons, we believe Mr. Willis is qualified to serve on the board.

Thomas M. Lewry. Thomas M. Lewry has served as a Director and as the Vice President of Investor Relations of the Company since 1995. Mr. Lewry has been responsible for shareholder relations. Mr. Lewry served as President of Settle Oil and Gas Company from 1990 to 1995, until it merged with Century Oil Company in August 1995. Mr. Lewry has also served as the President and Chief Executive Officer of Curbstone Financial Management Corporation, a financial services firm in Manchester, New Hampshire, since 1982. Mr. Lewry is a member of the Financial Industry Regulatory Authority (FINRA), International Association of Financial Planners, American Society of Certified Financial Planners, and is a registered investment adviser with the Securities and Exchange Commission (SEC). He was also the Chairman of the Business Conduct Committee, New England Region National Association of Securities Dealers. Mr. Lewry completed his Bachelor of Science degree in finance from Pennsylvania State University, and is a Certified Financial Planner (CFP).

Mr. Lewry brings extensive executive and financial expertise to the board from his executive officer positions at various companies and his membership in FINRA, the International Association of Financial Planners, the American Society of Certified Financial Planners, and as a registered investment adviser with the SEC. For these reasons, we believe Mr. Lewry is qualified to serve on our board.

Robert E. Fox. Robert E. Fox has served as a Director of the Company since 1995. Mr. Fox has also served as a consultant to the Company since 1995. Mr. Fox has been working as an oil and gas consultant since 1986. He has extensive experience in the oil and gas industry. Mr. Fox also served on the Board of Directors of DeepTech International, Inc., a diversified energy company working in the Gulf of Mexico, a position which he has held from 1996 to 1998. Mr. Fox’s experience in the oil and gas industry spans 59 years and includes experiences in the United Kingdom, Netherlands (North Sea), Africa, and the United States. Mr. Fox has served on the Board of Directors of Oil Exploration, Ltd. from 1974 to 1978, and LASMO, Plc from 1979 to 1986. He was also Chairman of Richmond Oil & Gas, Plc from 1990 to 1993 and a Director of Term Energy Corporation from 1981 to present. Mr. Fox is a member of the Geological Society of America, American Association of Petroleum Geologists, Society of Petroleum Engineers of AIME. He completed his Master of Science Degree in Geology from the University of Illinois and his bachelor of science degree from Marshall University, West Virginia. He was also given a D.Sc. (Honorary) in Engineering from Heriot-Watt University, Edinburgh, Scotland, and a D. of Humane Letters (Honorary) from Marshall University.

Mr. Fox’s over 59 years of experience in the oil and gas industry, his experience as both an executive and a board member of various energy companies, and his membership in the Geological Society of America, the American Association of Petroleum Geologists, the Society of Petroleum Engineers of AIME, and the American Institute of Professional Geologists make him well-qualified to serve on our board.

Jeff T. Craycraft. Jeff T. Craycraft has served as our Chief Financial Officer and Treasurer since 1997. Mr. Craycraft served as the Controller of Century Offshore Management Company, predecessor to RAAM Global Energy Company, from 1986 to 1990 and Vice President of Administration from 1990 to 1997. Simultaneously he served as Controller of Century Oil Company from 1989 to 1995. Mr. Craycraft was a staff accountant and programmer at Settle & Holt, a certified public accounting firm, from 1980 to 1983.

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Prior to 1980, he was employed at Malcolm Saunier & Company, a certified public accounting firm as a staff accountant and spent seven years at various administrative and management roles for what is now called CSX Corporation formerly Chesapeake & Ohio Railroad. Mr. Craycraft is a member of the American Institute of Certified Public Accountants and the Kentucky Society of Certified Public Accountants. He received his bachelor of science degree in accounting from the University of Kentucky.

Ken Young. Ken Young has served as Chief Operating Officer for RAAM Global Energy since October 2012. In this position, he directs the technical evaluation and operations for RAAM Global Energy and its wholly owned subsidiaries. Mr. Young has 30 plus years of experience in conventional and unconventional resource plays. Mr. Young’s expertise is in creating value by working with the right people to develop the right assets through application of state-of-the-art technology in defining the risk-reward to make best economic decisions at the right time. Prior to joining RAAM Global Energy Mr. Young was the Executive Vice President of Exploration for Vitruvian Exploration and was instrumental in the success of the Company. Mr. Young was the founder of New Trials Energy and co-founder of Rainier Exploration. Mr. Young also worked in technical and managerial role for Tenneco Oil, Zilkha Energy, Hardy Oil and Cockrell Oil. Mr. Young is a graduate of Pennsylvania State University with B.S. in Geoscience and South Dakota School of Mines & Technology with M.S. in Geological Engineering.

Elizabeth A. Barr. Elizabeth A. Barr has served as Vice President of Administration for the Company since 2007. From 1990 to 2007, Ms. Barr served as our Controller. As Controller, she was responsible for financial statement preparation and working with the Company’s outside audit firm in the preparation of the annual audit. Prior to joining the Company, Ms. Barr was an audit manager with Coopers & Lybrand for nine years. Ms. Barr is a member of the American Institute of Certified Public Accountants and the Kentucky Society of Certified Public Accountants. Ms. Barr holds a master of science degree in Business Administration from the University of Kentucky and a bachelor of arts degree in Business Administration and Computer Science from Transylvania University.

Code of Ethics

We have adopted a Code of Ethics, which applies to our principal executive officer, principal financial officer and principal accounting officer. Our Financial Code of Ethics is posted on our website. You may request a copy of our Code of Business Conduct and Financial Code of Ethics, without charge, from our Compliance Officer at 1537 Bull Lea Rd., Suite 200, Lexington, Kentucky 40511 or by calling (859) 253-1300.

Corporate Governance

Our board of directors has appointed an audit committee and a compensation committee. We do not have a nominating committee. Messrs. Settle, Rudney, Willis, Lewry and Fox serve as the members of the audit committee and the compensation committee. Because we do not have and are not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors or designate an audit committee financial expert. Accordingly, our board of directors has not made any determination as to whether any of the members of our board of directors or committees thereof would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition.

Item 11. Executive Compensation

Compensation Discussion and Analysis

During 2014, our executive compensation program was overseen by the Compensation Committee of our Board of Directors (the “Compensation Committee”). Our chief executive officer reviewed compensation for all of our named executive officers other than himself, and made compensation recommendations to the Compensation Committee. The Compensation Committee then evaluated the chief executive officer’s recommendations and conducted its own independent review and evaluation of the chief executive officer’s compensation and made all final compensation decisions for our named executives by exercising its discretion in accepting, modifying or rejecting any management recommendations as it deemed appropriate.

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The Compensation Committee generally approves any changes to base salary levels, bonus opportunities and other annual compensation components by the end of December or early in the new year, with such changes becoming effective as of January 1^stof the year to which the changes relate.

The named executive officers for our fiscal year ending December 31, 2014 (the “2014 Fiscal Year”), and who are described in this Compensation Discussion and Analysis section, are:

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Howard A. Settle – President and Chief Executive Officer (our “CEO”)

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Jeffrey T. Craycraft – Treasurer and Chief Financial Officer

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Ken Young – Chief Operating Officer

•

Elizabeth A. Barr – Vice President of Administration

•

Michael J. Willis – Senior Vice President

•

Jerry L. Sheets – Senior Vice President of Land and Business Development

Mr. Sheets’ employment with the Company was terminated on November 17, 2014 and pursuant to SEC disclosure requirements he was still a named executive officer for the 2014 year.

Objectives of Our Executive Compensation Program

The goal of the executive compensation program is to attract and retain excellent management with the requisite experience and managerial skills to achieve the goals of the strategic business plan of our company. The strategic business plan sets out a targeted production rate and reserve value for each of the core areas of our company that, collectively, will generate a specific Adjusted EBITDA within five years. We track the production growth, reserve growth, capital expenditures, revenues, and Adjusted EBITDA figures and compare these figures to our established goals to determine if objectives are being achieved. Our evaluation of results is an ongoing process that is updated monthly. The Compensation Committee reviews these periodic findings with respect to our business plan when it completes its annual compensation review or when it makes any changes to our compensation program. The Compensation Committee strives to design our compensation program in a manner that successfully aligns our business goals with the interests of our named executive officers, which in turn ensures that our named executive officers interests are aligned with our stockholders interests.

We have not historically maintained a performance-based cash award or equity-based award program. Rather than provide an equity-based award program for stock grants, we maintain a plan for which applicable executive officers are eligible to participate in that provides a royalty interest in certain successful wells. These royalty interests are intended to bestow certain key employees with a short-term incentive to receive an interest grant, while also aligning the employee’s interest with our stockholders by providing the executives with a long-term, personal interest in our company. Grants under the royalty interest plan are intended to create alignment between executive compensation and our well production, and do not occur on a frequent basis. Messrs. Settle, Craycraft and Willis and Ms. Barr have received such royalty interest plan awards. When Messrs. Young and Sheets began their employment, we negotiated individualized incentive compensation arrangements with each of them that we believe also create an alignment between the executive’s compensation and our performance.

We do not specifically benchmark any element of our compensation program and we do not maintain a formulaic process for determining compensation relative to our peers, but we periodically assess our ability to provide competitive compensation packages to executive officers and make appropriate adjustments to our program when we deem it necessary. The base salaries of our named executive officers are set at a level that is commensurate with other companies in the industry of comparable size, and while salaries are reviewed on an annual basis, salaries will only be adjusted at times when we have determined that increases are necessary to allow the Company to compete for top managerial talent.

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To determine our competitiveness in our industry we review publicly available surveys and filings of companies that we deem to be our peers at the time, and although we have not historically engaged in formal consultations with third party consultants or advisors to receive this type of information, our Compensation Committee engaged BDO USA LLP, an independent compensation consultant, during the third quarter of the 2012 year to assist us in compiling more focused data on the compensation programs at our peer companies. The Compensation Committee used the resulting data when making compensation decisions with respect to the 2013 year. The Compensation Committee did not engage an independent compensation consultant during 2014 and at this time the Compensation Committee has no plans to engage an independent compensation consultant to assist the committee in making compensation decisions, but the Compensation Committee has the authority to engage such an outside consultant at any time if the Compensation Committee determined that such assistance would be appropriate.

Our current compensation policy is directed at achieving the corporate goals as established in the strategic plan of the Company. All executives are considered to be responsible for achieving these goals, and therefore the current compensation policy does not specifically look to measured performance for each named executive officer. Bonuses, when appropriate, may be structured to provide rewards upon payout of specific projects, and the amount of the award may be largely dependent on the magnitude of the project’s overall success. The Compensation Committee does, however, have the right to reward executives for outstanding individual performance, and has done so in the past with cash awards on a case by case basis.

Setting Executive Compensation

The Board has established a Compensation Committee which includes every member of the Board. The Board has adopted a Charter which sets the responsibilities and duties of the Compensation Committee, which may be found on our website under “Investor Relations” and then under “Corporate Governance.” The Compensation Committee has full discretion to administer the compensation program on a going forward basis.

Our CEO has been delegated the authority to hire and fire employees, and to set compensation for all employees other than executive officers. The Compensation Committee determines the compensation for all executive officers. With respect to executive officers, the role of the CEO is advisory with respect to everyone but himself; however, the CEO is also the Chairman of the Board, and is also on the Compensation Committee. As the Chairman of the Board, and a member of the Compensation Committee, the CEO attends all meetings of the Compensation Committee and the Board, although he recuses himself from meetings when his own compensation will be discussed or determined.

With respect to the After Payout Overriding Royalty Plan of RAAM Global Energy Company and Century Exploration New Orleans, LLC (the “APORRI Plan”), our CEO has appointed a special committee to administer the day to day functions of the plan. This employee incentive committee (the “Incentive Committee”) for the 2014 Fiscal Year was comprised of Howard Settle, Jeffrey Craycraft and Elizabeth Barr and was charged with the limited responsibility of administering the APORRI Plan. The Incentive Committee does not make decisions regarding the amounts of awards that will be granted pursuant to the APORRI Plan, nor does the Incentive Committee play a role in setting or administering any other portion of our compensation program.

Key Components of our Compensation Policy

Our compensation and benefits programs have historically consisted of the following components, which are described in greater detail below:

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Base salary;

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Annual cash bonuses;

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Royalty interest payments from producing wells (for applicable key employees);

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Participation in broad-based retirement, health and welfare benefits; and

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Limited perquisites.

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The royalty interest payments will be provided only when the applicable well is successfully producing profits, thus these payments are also a variable element of compensation that depends solely on the performance of the applicable well. The annual bonuses will also depend on performance in any given year, so are likewise not a guaranteed compensation component.

Base Salary

Each named executive officer’s base salary is a fixed component of compensation and provides each named executive officer with a steady stream of income throughout the calendar year. Base salaries are determined for each named executive based on his or her position and responsibility. We review the base salaries for each named executive annually as well as at the time of any promotion or significant change in job responsibilities, and in connection with each review we consider individual and company performance over the course of that year. Our Compensation Committee, provided for a 3% company-wide cost of living increase to the 2014 base salaries of all of our named executive officers. The base salary amounts that each of our named executive officers earned during the 2014 Fiscal Year is disclosed in the Summary Compensation Table below.

The Compensation Committee determined that each of the named executive officers should again receive a cost of living increase in base salaries for the 2015 year, thus we do not expect any officer will receive an increase of more than 3% in the 2015 year.

Discretionary Bonuses

Many of our employees received a $2,500 year-end bonus, and our Compensation Committee determined to provide the same bonus payment to Messrs. Craycraft, Young and Willis and Ms. Barr for the 2014 year. Mr. Sheets was no longer employed when these bonuses were granted.

Incentive Compensation Arrangements

APORRI Plan. The APORRI Plan is intended to promote the success of our company by providing certain key employees an “after payout” overriding royalty interest in successful wells. The interest granted pursuant to the APORRI Plan is a nonforfeitable ownership interest to the participant following the initial grant, which satisfies our goal of aligning our executive’s interests with those of our stockholders.

Participants in the APORRI Plan receive a number of APORRI units, and the overriding royalty percentage that the participant will receive upon a payout of the well will be calculated using the number of APORRI units assigned to the participant in relation to the aggregate number of APORRI units assigned to that well (the “APORRI Percentage”). We enter into individual agreements with each participant in the APORRI Plan that grants and conveys the royalty interest, including the title, rights, powers and privileges related to the royalty interest, to the participant as of the date that the well in question reaches a payout. Payouts for a well are considered “after payout” because payments to APORRI Plan award recipients occur when we have received net revenues from the production of a given well equal to our entire monetary investment in the well and the leasehold costs for the well.

Messrs. Settle, Craycraft, and Willis and Ms. Barr participate in the APORRI Plan. Each of them received their initial grant of APORRI units in previous years and certain of the wells associated with our named executive officer’s past grants were in payout during the 2014 Fiscal Year. We granted new APORRI Plan grants in three wells to the applicable participating named executive officers during the 2014 Fiscal Year. Messrs. Settle, Craycraft, and Willis and Ms. Barr are in the recipient pool for the APORRI Plan and receive their proportionate share of the 3% and 1 1/2% APORRI pool in each well drilled in Century Exploration New Orleans, LLC and Century Exploration Houston, LLC, respectively. This pool is proportionately reduced in wells that RAAM Global is not a 100% owner. Each of our service providers that receive a percentage in one of the APORRI Plan wells receives the percentage that has been pre-assigned to that individual’s position within the company; our Compensation Committee does not make individual decisions regarding the percentage that should be awarded to any named executive officer.

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In 2014, Messrs. Settle, Craycraft, and Willis and Ms. Barr received grants in three wells drilled in Century Exploration Houston, LLC. In the award granted March 22, 2014, each received a 0.143% APORRI in this well. In the award granted June 1, 2014, each received a 0.136% APORRI. In the award granted August 14, 2014, each received a 0.153% APORRI.

The aggregate amounts received by each named executive officer under the APORRI Plan for the 2014 Fiscal Year relating to previous APORRI Plan grants, as well as amounts relating to the new 2014 grants, are reported in the succeeding Summary Compensation Table.

Resource Royalty Plan. Mr. Settle also participates in an overriding royalty interest plan (the “Resource Royalty Plan”) that is based on wells of our subsidiary Century Exploration Resources, LLC (“Resources”). Our Board administers the Resource Royalty Plan and determined that certain executive officers who contributed to the success of the Resource wells should be rewarded and incentivized to create value for Resources by providing them with a percentage of the revenues from those wells. While Messrs. Young and Sheets provided certain services to Resources during the 2014 year, they are compensated pursuant to a different incentive arrangement described below, thus Mr. Settle is our only named executive officer that is directly involved in the Resource properties and who received grants pursuant to the Resource Royalty Plan. Like the APORRI Plan described above, a grant in the Resource Royalty Plan was designed as a percentage of a recipient pool for an applicable well. The difference in the two plans is that the APORRI Plan is an “after payout” overriding royalty interest, while the Resource Royalty Plan was designed to provide potential payments from a well prior to Resources recouping its expenses of development, operation, or maintenance. The aggregate amounts received by Mr. Settle under the Resources Royalty Plan for the 2014 Fiscal Year relating to previous Resource Royalty Plan grants, as well as amounts relating to the new 2014 grant, are reported in the succeeding Summary Compensation Table.

Annual Bonus Plan.

The 2014 bonus awards were granted under the Annual Bonus plan that the Compensation Committee implemented during the 2013 year. This plan is based on the Company meeting certain Reserve goals and certain Adjusted EBITDA goals for the applicable year. Employees are eligible to receive a certain percentage of their salary as an annual bonus, based upon the Company’s accomplishment of certain goals during the year. Any bonuses earned during the 2014 year will be paid out on or before March 15, 2015. In order to receive any bonus earned under this plan, an employee must still be employed by the Company when the bonus is paid. The percentage that an employee may receive of his base salary varies by rank and department. Messrs. Settle, Craycraft, and Willis and Ms. Barr were each eligible to receive up to 30% of their base salary under this bonus plan. Mr. Young was eligible to receive up to 150% of his base salary under this bonus plan. Bonuses for all departments were based 50% on meeting an Adjusted EBITDA goal (described below) and 50% on a reserve value goal (described below). Mr. Sheets was no longer employed by the Company prior to the payment of this bonus.

The goals for the 2014 Annual Bonus plan were based on an Adjusted EBITDA goal and a reserve value goal. We feel Adjusted EBITDA and reserve value are key metrics for determining the success of our business. The minimum Adjusted EBITDA for a bonus payout for the year was $85.0 million and the minimum reserve value at December 31, 2014 for a bonus payout was $350.0 million. The Company did not meet these goals and therefore no bonus will be paid under the Annual Bonus Plan for the 2014 year.

Employment Agreements, Severance and Change in Control Benefits

We entered into new employment agreements with each of Messrs. Young and Sheets on February 26, 2013. Each agreement had an initial one-year term that automatically renews for successive one-year periods until terminated in writing by either party at least 30 days prior to a renewal date. Each agreement provided the named executive officer with a minimum annual base salary ($425,000 in the case of Mr. Young and $325,000 in the case of Mr. Sheets) during the term and each of Messrs. Young and Sheets was also eligible to receive an annual cash bonus, with a target amount equal to 150% of his base salary under our Annual Bonus Plan. Additionally, each of Messrs. Young and Sheets was eligible to receive discretionary commission payments. Finally, each of Messrs. Young and Sheets was eligible to participate in the health insurance, retirement and other perquisites and benefits of the Company as in effect from time to time on terms no less favorable than those provided to other similarly situated employees of the Company.

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Pursuant to the terms of their respective employment agreements, each of Messrs. Young and Sheets would have been entitled to severance payments in certain limited circumstances, but in November 2014, the Company determined that it would no longer maintain employment agreements with any employees and therefore did not renew Mr. Young’s agreement. As discussed previously, Mr. Sheets’ employment with the Company was terminated on November 17, 2014.

Other than as noted for Messrs. Young and Sheets, the named executive officers did not have agreements with us that contained severance provisions and/or change in control payment provisions during the 2014 Fiscal Year, and as of the end of the 2014 Fiscal Year, we no longer maintain any such agreements with any named executive officer.

Other Benefits

401(k) Retirement Savings Plan. Our 401(k) Plan is designed to encourage all employees, including the participating named executive officers, to save for the future. Under our 401(k) Plan, we match employee contributions, including those made by our named executive officers, at rates approved by our Board. For fiscal 2013, we matched 100% of the first 8% of eligible pre-tax earnings (up to IRS limits) contributed by plan participants.

Health and Welfare. All employees, including the named executive officers, also receive health and welfare benefits.

Perquisites. We do not feel that it is necessary to provide perquisites to our named executive officers in order to supplement the compensation and benefits that are provided to them through other aspects of our compensation program. Our Compensation Committee intends to design any perquisites that may be provided to our executives in the future as having a legitimate business purpose, and where possible, capped at de minimis levels.

Other Compensation Items

We do not directly maintain any long-term equity-based incentive and/or stock option plans for our named executive officers. Each named executive officer owns shares of the company, and there are no restrictions at this time on executives acquiring or selling stock of the company. Our company shares are not traded publicly and therefore there are no hedging prohibitions nor is there any opportunity to hedge against the company’s share value.

Risk Assessment

The Board has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that they do encourage is not reasonably likely to have a material adverse effect on us.

Our compensation philosophy and culture support the use of base salary, certain performance-based compensation, and retirement plans that are generally uniform in design and operation throughout our organization and with all levels of employees. These compensation policies and practices are centrally designed and administered, and are substantially identical between our business divisions. In addition, the following specific factors, in particular, reduce the likelihood of excessive risk-taking:

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Our overall compensation levels are competitive with the market.

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Our compensation mix is balanced among (i) fixed components like salary and benefits and (ii) annual incentives that reward our overall financial performance, business unit financial performance, operational measures and individual performance.

In summary, although a portion of the compensation provided to named executive officers is based on our performance or individual successes of the employee, we believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees) because these programs are designed to encourage employees to remain focused on both our short- and long-term operational and financial goals. We set performance goals that we believe are reasonable in light of our past performance and market conditions.

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Compensation Committee Report

During the last fiscal year, and this year in preparation for the filing of this annual report with the SEC, the Compensation Committee:

•

reviewed and discussed the disclosure set forth under the heading “Compensation Discussion and Analysis” with management; and

•

based on the reviews and discussions referred to above, recommended to the Board of Directors that the disclosure set forth under the heading “Compensation Discussion and Analysis” be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Respectfully submitted by the Compensation Committee of the Board of RAAM Global Energy Company

Tom Lewry (Chairman)

Howard Settle

Robert Fox

Jonathan Rudney

Michael Willis

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Summary Compensation Table

The table below sets forth the annual compensation earned during the 2014, 2013, and 2012 fiscal years by our “named executive officers,” as of December 31, 2014:


Name and Principal Position	Year		Salary ($)		Bonus ($)(1)		Non-Equity Incentive Plan Compensation ($) (2)		All Other Compensation ($)(3)		Total ($)
Howard A. Settle		2014		332,910		—		213,328		23,000		569,238
President and Chief Executive Officer, Director		2013		320,604		5,000		270,016		21,920		617,540
		2012		282,563		5,000		396,301		22,500		706,364
Jeff T. Craycraft		2014		231,188		2,500		170,170		18,495		422,353
Treasurer and Chief Financial Officer		2013		221,271		5,000		166,307		16,952		409,530
		2012		179,812		5,000		216,261		14,385		415,458
Ken Young		2014		436,688		2,500		—		14,507		453,695
Chief Operating Officer		2013		425,833		494,263		191,250		13,833		1,125,179
Elizabeth A. Barr		2014		231,188		2,500		170,170		18,495		422,353
Vice President of Administration
Michael Willis		2014		226,050		2,500		170,170		18,084		416,804
Senior Vice President, Director
Jerry Sheets		2014		320,204		—		—		22,217		342,421
Senior Vice President		2013		325,833		494,263		146,250		10,500		976,846

(1)	The amounts included in the Bonus line for 2014 represent a $2,500 year-end discretionary bonus.

(2)

As noted above, no amounts were paid to the executives under the Annual Bonus Plan for 2014. Amounts represent the aggregate royalty payments received from the APORRI Plan for each of the named executive officers other than Mr. Settle. For Mr. Settle, the amount includes $188,970 received from the APORRI Plan during the 2014 year and $24,358 received from the Resource Royalty Plan.

(3)	The amounts included in the Other Compensation line for all named executives officers relate solely to matching contributions to each employee’s 401(k) Plan account.

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Grants of Plan-Based Awards for the 2014 Fiscal Year


	Grant	Possible Payouts under Non-Equity Incentive Plan Awards
Name	Date(1)	($)(2)
Howard A. Settle	3/22/14	$	7,469
	6/1/14	$	5,303
	8/14/14	$	7,469
	10/12/14	$	3,572
Jeff T. Craycraft	3/22/14	$	7,469
	6/1/14	$	5,303
	8/14/14	$	7,469
Elizabeth A. Barr	3/22/14	$	7,469
	6/1/14	$	5,303
	8/14/14	$	7,469
Michael Willis	3/22/14	$	7,469
	6/1/14	$	5,303
	8/14/14	$	7,469

(1)	Grant dates vary by well, as noted in the Compensation Discussion and Analysis above.

(2)

The values shown in this column represent the actual amount of payments that each of the named executive officers received from grants in the APORRI Plan, and with respect to Mr. Settle, from the Resource Royalty Plan, that occurred in the 2014 year. Mr. Settle’s October 12, 2014 grant was made pursuant to the Resource Royalty Plan, while the remaining grants shown for Mr. Settle were made under the APORRI Plan. We believe that an estimation of future payouts under these grants is undeterminable at this time, as a well could stop producing at any given time and payout streams are unpredictable and undeterminable at this time.

Narrative Description to the Summary Compensation Table and the Grant of Plan-Based Awards Table for the 2014 Fiscal Year

Percentage of Salary and Bonus in Comparison to Total Compensation


Name	Salary and Bonus Percentage of Total Compensation
Howard A. Settle		58	%
Jeff T. Craycraft		55	%
Ken Young		97	%
Elizabeth A. Barr		55	%
Michael Willis		55	%
Jerry L. Sheets		94	%

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Outstanding Equity Awards at 2014 Fiscal Year-End

None of our named executive officers held outstanding equity awards as of December 31, 2014.

Stock Vested in the 2014 Fiscal Year

None of our named executive officers experienced a vesting event on outstanding equity awards during the 2014 Fiscal Year.

Pension Benefits

We maintain a 401(k) Plan for our employees, including our named executive officers, but at this time we do not sponsor or maintain a pension plan for any of our employees.

Nonqualified Deferred Compensation

We do not provide a nonqualified deferred compensation plan for our employees at this time.

Potential Payments Upon Termination or a Change in Control

As noted above in the Compensation Discussion and Analysis, we do not provide any of our named executive officers with individual severance or change in control benefit agreements at this time. Although we maintained an individual employment agreement with both Messrs. Young and Sheets during portions of the 2014 Fiscal Year, as of December 31, 2014, neither one of those agreements were in effect.

Mr. Sheets’ employment was terminated on November 17, 2014. Pursuant to the terms of his employment agreement, he received a one-time separation payment of $41,269 less applicable tax and withholdings, which represents an amount equal to the amount of base salary he would have earned had he remained employed by the Company until December 31, 2014. Mr. Sheets is included in this discussion because he would have been one of our named executive officers for the 2014 Fiscal Year had he remained employed by the Company.

Director Compensation


Name	Fees Earned or Paid in Cash ($)		Total ($)
Robert E. Fox		10,000		10,000

Robert E. Fox is paid a $2,500 retainer per calendar quarter for his service as a member of the Board. Jonathan B. Rudney did not receive compensation for his service as a member of the Board, other than reimbursement of his travel expenses to attend meetings.

Thomas M. Lewry is an employee of the Company that does not receive any additional compensation for serving on our Board. Two of our named executives officers, Howard Settle and Michael Willis, are also members of our Board and do not receive additional compensation for their service on the Board; their compensation for the 2014 Fiscal Year is reported in the Summary Compensation Table above. The time spent on Board activities for these employees is considered to be a portion of the duties of their position with us, thus they do not receive additional compensation for being on the Board.

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Compensation Committee Interlocks and Insider Participation

Our Compensation Committee is made up of our entire Board of Directors. All Board members except Mr. Fox and Mr. Rudney are executive officers of the Company. The Compensation Committee has no interlocks. During the year ended December 31, 2014, Mr. Settle and Mr. Rudney participated in related party transactions with the Company. For a description of these transactions, see Item 13. “Certain Relationships and Related Transactions, and Director Independence.”

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Equity Compensation Plan Information

The Company does not maintain an equity incentive compensation plan.

RAAM Global Energy Company Common Stock

The following table sets forth information regarding the beneficial ownership of our common stock as of March 27, 2015 for:

•

each person known by us to beneficially own more than 5% of our common stock;

•

each of our directors;

•

each of our executive officers and key employees; and

•

all our directors, executive officers and key employees as a group.

As of March 27, 2015, we had 61,433 outstanding shares of our common stock. Footnote 1 to the following table provides a brief explanation of what is meant by the term “beneficial ownership.” The number of shares of common stock and the percentages of beneficial ownership are based on 61,433 shares of common stock issued and outstanding as of March 27, 2015. The amounts presented may not add due to rounding.

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To our knowledge and except as indicated in the footnotes to this table and subject to applicable community property laws, the persons named in this table have the sole voting power with respect to all shares of common stock listed as beneficially owned by them.


Name and Address of Beneficial Owner⁽¹⁾⁽²⁾	Amount and Nature of Beneficial Ownership		Percentage of Common Stock Beneficially Owned
Directors, Executive Officers and Key Employees:
Howard A. Settle		29,692.56		48.33	%
Jonathan B. Rudney		7,800.35		12.70	%
Thomas M. Lewry		1,581.53		2.57	%
Jeffrey T. Craycraft		600.00		*	%
Elizabeth A. Barr		364.00		*	%
Michael J. Willis		250.00		*	%
Ken Young		167.64		*	%
Robert E. Fox		150.00		*	%
All Directors and Executive Officers as a Group (8 persons)		40,606.08		66.10	%
Other		20,826.69		33.90	%
Total		61,432.77		100.00	%

*	Less than 1% of our common stock.

(1)

“Beneficial ownership” is a term broadly defined by the SEC in Rule 13d-3 under the Exchange Act and includes more than the typical forms of stock ownership, that is, stock held in the person’s name. The term also includes what is referred to as “indirect ownership,” meaning ownership of shares as to which a person has or shares investment or voting power, or a person who, through a trust or proxy, prevents the person from having beneficial ownership. For the purpose of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares as of March 27, 2015, if that person or group has the right to acquire shares within 60 days after such date.

(2)	The address for each director, executive officer and key employee is c/o RAAM Global Energy Company, 1537 Bull Lea Rd., Suite 200, Lexington, Kentucky 40511.

Item 13. Certain Relationships and Related Transactions, and Director Independence

For a description of director independence, see Item 10. “Directors, Executive Officers and Corporate Governance.”

The following paragraphs provide information regarding the related party transactions which have been entered into and affect the financial statements of RAAM as of December 31, 2014.

During 2003, we entered into a lease with ATMA Investments, LLC for our Lexington, Kentucky office space. ATMA Investments, LLC is an entity wholly-owned by Howard A. Settle. The initial lease rate was $17.50/sq. ft., with a 3% escalation per year, plus other costs. For the year ended December 31, 2014, the Company paid ATMA Investments, LLC $228,000 under the lease.

RAAM Exploration LLC was formed by Howard Settle and his wife, Alice Settle, to participate as a working interest partner with 17.5% to 25% interests in our wells, mainly in the Bayou Postillion, Breton Sound and Main Pass fields. An Exploration Agreement was approved by the Board of RAAM in 2004 which set forth the participation rights to acquire working interests in prospects developed by RAAM. In 2008, RAAM Exploration assigned its rights pursuant to the December 2004 Agreement to RAM Development LLC effective January 2008. During 2008, Mr. and Mrs. Settle donated this entity to a charitable foundation and appointed an attorney as president of the charitable entity. Subsequent to this donation, the properties owned by RAAM Exploration LLC were sold to RAAM and its subsidiaries which include Sita Energy, LLC, Century Exploration Resources, LLC and Windstar Energy, LLC as the replacement property in a 1031 exchange transaction for cash of approximately $63 million and a note. The note was exchanged for an overriding royalty whereby RAAM Exploration LLC receives a 10% overriding royalty interest on four properties of Century Exploration New Orleans, LLC and Century Exploration Houston, LLC for the balance of the purchase price, $24.3 million plus interest of 8%. During 2010, the Board agreed to assign the 10% overriding royalty interest as an unrestricted 10% royalty to the Howard and Alice Settle Foundation. As of December 31, 2013, the Company had payables due to the Howard and Alice Settle Foundation of $0.1 million.

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RAM Development LLC, wholly owned by Howard A. Settle, entered into an Exploration Agreement with the Company and RAAM Exploration LLC in 2008. The RAM Development LLC was a partner in wells drilled by both by Century Exploration New Orleans, LLC and Century Exploration Houston, LLC. During 2009, the Exploration Agreement was terminated and RAM Development LLC relinquished its contractual right to a 25% working interest in various proved producing properties, proved undeveloped properties and various exploration prospects. As a result of the relinquishment, the Company has agreed to carry RAM Development LLC on certain wells to be determined at the sole discretion of the Board of Directors of RAAM and will be determined on a well by well basis. In addition, specific projects are identified in the agreement as to a carried interest for RAM Development LLC. During 2010, the Board agreed to provide a 25% carried interest to RAM Development LLC for the Flipper, Redfish, Saturn, Barracuda and Briscoe Bayou projects. Since the drilling of Redfish and Saturn has been delayed, in large part due to the repercussions of the Macondo oil spill, the Board agreed to replace those wells with four prospects to be drilled onshore and include Jacques, Sebastian, Perry and Pilgrim Church. During the second quarter of 2014, the Company purchased working interests in 19 wells located onshore Texas that represented 0.5 MBOE of reserves from RAM Development LLC for a net purchase price of $4.9 million. The Company obtained a reserve report from independent reserve engineers, which was used to help determine the purchase price. The purchase was approved by the Company’s Board of Directors.

Charter IV Inc. was incorporated during 2008 and Charter V Inc. was incorporated during 2010. Certain employees of RAAM Global Energy Company, Century Exploration New Orleans, LLC and Century Exploration Houston, LLC are the shareholders of these corporations. Certain of our officers and directors, including Howard Settle, Michael Willis, Jeffrey Craycraft, and Elizabeth Barr, participate in Charter IV Inc. and Charter V Inc. (“the Charters”). The Charters are working interest partners in certain oil and gas properties operated by Century Exploration New Orleans, LLC and Century Exploration Houston, LLC. Officers in each entity include Jeff Craycraft, President, Leon Smith, Vice President and Elizabeth Barr, Secretary/Treasurer. Neither of the Charters have employees and employees of the Company provide the accounting services for each entity. The Company finances Charter IV Inc. and Charter V Inc. and all revenues from producing properties are paid to the Company in order to reduce Charter IV Inc.’s, and Charter V Inc.’s respective joint interest billings owed to the Company. Charter V Inc. owns various producing properties and is currently paying down its respective joint interest accounts. The Company has determined that the Charters are variable interest entities (“VIEs”) and the Company is the primary beneficiary of these VIEs; therefore, in accordance with FASB guidance on accounting for VIEs, the Charters are consolidated in the Company’s annual financial statements. During the second quarter of 2014, the Company entered into an agreement to purchase all of the issued and outstanding equity of Charter V from the Sellers of Charter V for a net purchase price of approximately $5.9 million. The aggregate consideration was based upon a Charter V reserve report from independent reserve engineers. The purchase was approved by the Company’s Board of Directors. Charter V held reserves totaling 0.4 MBOE. The Sellers consist of 46 individuals who were employees of the Company as of December 31, 2010. The Company completed the purchase on July 2, 2014.

The Company awarded overriding royalty interests to certain of the Company’s officers and directors, including Howard Settle, Jeffrey Craycraft, Elizabeth Barr and Michael Willis, under the APORRI Program. Overriding royalty interests are designated by the Company’s employee incentive committee on a well-by-well basis, with preference being given to members of senior management and key technical personnel.

Policies and Procedures

We review all relationships and transactions in which we and our directors and executive officers or their immediate family members are participants to determine whether such persons have a direct or indirect material interest. Our President is primarily responsible for the development and implementation of procedures and controls, as set forth in our Related Persons Transaction Policy, to obtain information from the directors and executive officers with respect to related person transactions and for subsequently determining, based on the facts and circumstances disclosed to them, whether we or a related person has a direct or indirect material interest in the transaction. As required under the SEC’s rules, transactions that are determined to be directly or indirectly material to us or a related person will be filed with the SEC when required, and disclosed in our annual reports.

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Our Code of Business Conduct and Financial Code of Ethics discourages all conflicts of interest and provides guidance with respect to conflicts of interest. Under the Code of Business Conduct and Financial Code of Ethics, conflicts of interest occur when private or family interests interfere in any way with the interests of our company. Our restrictions on conflicts of interest under the Code of Business Conduct and Financial Code of Ethics include related person transactions.

We have multiple processes for reporting conflicts of interests, including related person transactions. Under the Financial Code of Ethics, all employees are required to report any actual or apparent conflict of interest, or potential conflict of interest, to their supervisors and all related person transactions involving our regional or market executives must be communicated in writing as part of their quarterly representation letter. This information is then reviewed by our Audit Committee, our Board of Directors or our independent registered public accounting firm, as deemed necessary, and discussed with management. As part of this review, the following factors are generally considered:

•

the nature of the related person’s interest in the transaction;

•

the material terms of the transaction, including, without limitation, the amount and type of transaction;

•

the importance of the transaction to the related person;

•

the importance of the transaction to us;

•

whether the transaction would impair the judgment of a director or executive officer to act in the best interest of our company;

•

any other matters deemed appropriate with respect to the particular transaction.

Ultimately, all such transactions must be approved or ratified by our Board of Directors in accordance with our Related Persons Transactions Policy. Any member of our Board of Directors who is a related person with respect to a transaction is recused from the review of the transaction.

In addition, we annually distribute a questionnaire to our executive officers and members of our Board of Directors requesting certain information regarding, among other things, their immediate family members, employment and beneficial ownership interests. This information is then reviewed for any conflicts of interest under the Financial Code of Ethics. At the completion of the annual audit, our Audit Committee and the independent registered public accounting firm review with management, insider and related person transactions and potential conflicts of interest. In addition, our internal audit function has processes in place to identify related person transactions and potential conflicts of interest and report them to senior management and the Audit Committee.

Our Financial Code of Ethics is posted on our corporate website. You may request a copy of our Code of Business Conduct and Financial Code of Ethics from our Compliance Officer at 1537 Bull Lea Rd., Suite 200, Lexington, Kentucky 40511 or by calling (859) 253-1300.

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Item 14. Principal Accounting Fees and Services

During the 2014 fiscal year, Ernst & Young LLP served as the Company’s Independent Auditors and also provided certain tax services. The aggregate fees billed to the Company by Ernst & Young LLP for services performed during the fiscal years ended December 31, 2014 and 2013 are as follows:


*(In thousands)*	2014		2013
Audit Fees	$	454	$	380
Audit Related Fees⁽¹⁾	$	—	$	156
Tax Fees	$	216	$	115
All Other Fees⁽²⁾	$	2	$	2

Total	$	672	$	653

(1)	The $156,000 in the audit related fees includes $78,000 in fees for the New Additional Notes Offering and Registration Statement on Form S-4 filed in conjunction with that offering and $78,000 in fees for the restatement of our 2012 financial statements.

(2)	All Other Fees is made up of a subscription to an accounting research tool that the Company purchases from Ernst & Young LLP each year.

The Company established its Audit Committee in February 2011. The Audit Committee approves all services provided to the Company by Ernst & Young LLP. The Audit Committee has a clear understanding with management and the independent auditors that the independent auditors are ultimately accountable to the Audit Committee, as representatives of the Company’s shareholders. The Audit Committee has the ultimate authority and responsibility to select, compensate, evaluate and, where appropriate, terminate and replace the independent auditors, and the independent auditors shall be ultimately accountable to the Audit Committee. Annually, the Audit Committee will review and recommend to the Board the selection of the Company’s independent auditors.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)

(1) Financial Statements

Financial statements included as part of this Form 10-K are set forth in Part II, Item 8.

(2) Financial Statement Schedules

All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

(3) Exhibits

Those exhibits required to be filed by Item 601 of Regulation S-K are listed in the Exhibit Index immediately preceding the exhibits filed herewith and such listing is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lexington, State of Kentucky, on March 31, 2015.


RAAM Global Energy Company

By:		/s/ Howard A. Settle
		Howard A. Settle
		President and Chief Executive Officer

This Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 31, 2015.


Signature	Title	Date

/s/ Howard A. Settle	President, Chief Executive Officer and Chairman	March 31, 2015
Howard A. Settle	(Principal Executive Officer)

/s/ Jeff T. Craycraft	Treasurer, Vice President and Chief Financial Officer	March 31, 2015
Jeff T. Craycraft	(Principal Financial and Accounting Officer)

/s/ Michael J. Willis	Director	March 31, 2015
Michael J. Willis

/s/ Jonathan B. Rudney	Director	March 31, 2015
Jonathan B. Rudney

/s/ Thomas M. Lewry	Director	March 31, 2015
Thomas M. Lewry

/s/ Robert E. Fox	Director	March 31, 2015
Robert E. Fox

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GLOSSARY OF OIL AND NATURAL GAS TERMS

We have included below the definitions for certain oil and natural gas terms used in this Annual Report:

“3-D seismic” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two dimensional, seismic.

“Analogous reservoir” Analogous reservoir, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest: same geological formation (but not necessarily in pressure communication with the reservoir of interest), same environment of deposition, similar geological structure, and same drive mechanism.

“Basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl” One stock tank barrel or 42 United States gallons liquid volume of oil or other liquid hydrocarbons.

“Bcf” One billion cubic feet of natural gas.

“Boe” One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil.

“Boepd” BOE per day.

“Bopd” Barrels of oil per day.

“Btu” A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one–pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Condensate” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“Developed acreage” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed oil and gas reserves” Reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

•

gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, natural gas lines, and power lines, to the extent necessary in developing the proved reserves;

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•

drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;

•

acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

•

provide improved recovery systems.

“Development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole or well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

“Farm-in” An agreement between a participant who brings a property into the venture and another participant who agrees to spend an agreed amount to explore and develop the property and has no right of reimbursement but may gain a vested interest in the venture. A “farm-in” describes the position of the participant who agrees to spend the agreed-upon sum of money to gain a vested interest in the venture.

“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation” A layer of rock which has distinct characteristics that differ from nearby rock.

“Gross acres or gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

“Henry Hub” The pricing point for natural gas futures contracts traded on the NYMEX.

“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Lease operating expenses” The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

“MBbl” One thousand barrels of oil or other liquid hydrocarbons.

“MBoe” One thousand barrels of oil equivalent.

“Mcf” One thousand cubic feet of natural gas.

“Mcfpd” One thousand cubic feet of natural gas per day.

“MMBbl” One million barrels of oil or other liquid hydrocarbons.

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“MMBoe” One million barrels of oil equivalent.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“MMcfpd” One million cubic feet of natural gas per day.

“Natural gas liquids” The hydrocarbon liquids contained within natural gas.

“Net acres or net wells” The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

“NYMEX” The New York Mercantile Exchange.

“Oil” Crude oil and condensate.

“Pay” The vertical thickness of an oil and natural gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.

“PDNP” Proved developed non-producing.

“PDP” Proved developed producing.

“Plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

“Producing well” A well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

“Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and natural gas produced. Examples of production costs (sometimes called lifting costs) are:

•

costs of labor to operate the wells and related equipment and facilities;

•

repairs and maintenance;

•

materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities;

•

property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

•

severance taxes.

“Productive well” An exploratory, development or extension well that is not a dry well.

“Proved reserves” Those quantities of oil and gas, which, 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 — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“PUD” Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

“Reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

“Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserve life” A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

“Reserves” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Sand” A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.

“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Successful well” A well capable of producing oil and/or natural gas in commercial quantities.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Wellbore” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“Working interest” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover” Operations on a producing well to restore or increase production.

128

INDEX TO EXHIBITS


Exhibit Number		Description

3.1		Certificate of Incorporation of RAAM Global Energy Company, dated November 19, 2003 (Incorporated by reference to Exhibit 3.1 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

3.2		Bylaws of RAAM Global Energy Company (Incorporated by reference to Exhibit 3.2 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

4.1		Indenture, dated as of September 24, 2010, among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (Incorporated by reference to Exhibit 4.1 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

4.2		First Supplemental Indenture, dated as of July 15, 2011, by and among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (Incorporated by reference to Exhibit 4.2 to RAAM Global Energy Company’s Current Report on Form 8-K filed on July 19, 2011 (File No. 333-172897)).

4.3		Second Supplemental Indenture, dated as of April 11, 2013, by and among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (Incorporated by reference to Exhibit 4.2 to RAAM Global Energy Company’s Current Report on Form 8-K filed on April 11, 2013 (File No. 333-172897)).

4.4		Third Supplemental Indenture, dated as of April 11, 2013, by and among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (Incorporated by reference to Exhibit 4.3 to RAAM Global Energy Company’s Current Report on Form 8-K filed on April 11, 2013 (File No. 333-172897)).

4.5		Registration Rights Agreement, dated April 11, 2013, among RAAM Global Energy Company, the several guarantors named therein, and Global Hunter Securities, LLC (Incorporated by reference to Exhibit 4.1 to RAAM Global Energy Company’s Current Report on Form 8-K filed on April 11, 2013 (File No. 333-172897)).

4.6		Intercreditor Agreement, dated as of September 24, 2010, by and among Union Bank, N.A., as administrative agent for the first lien creditors named therein, the Bank of New York Mellon Trust Company, N.A., as indenture trustee for the second lien creditors named therein, Century Exploration New Orleans, Inc., Century Exploration Houston, Inc and RAAM Global Energy Company (Incorporated by reference to Exhibit 4.3 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

4.7		Security Agreement, dated September 24, 2010, by RAAM Global Energy Company and the several guarantors name therein in favor of Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (Incorporated by reference to Exhibit 4.4 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

10.1		Promissory Note, dated August 8, 2005, between RAAM Global Energy Company and GE Commercial Finance Business Property Corporation (Incorporated by reference to Exhibit 10.6 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

129


Exhibit Number		Description

10.2†		Form of Stock Purchase Agreement, effective August 24, 2011, between the Sellers defined therein and RAAM Global Energy Company (Incorporated by reference to Exhibit 10.10 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on August 29, 2011 (Reg. No. 333-172897)).

10.3		Lease Agreement, dated January 1, 2011, between ATMA Investments, LLC and RAAM Global Energy Company (Incorporated by reference to Exhibit 10.11 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

10.4		December 2004 Agreement, dated December 1, 2004, between RAAM Global Energy and RAAM Exploration LLC (Incorporated by reference to Exhibit 10.12 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

10.5		Termination of the December 2004 Agreement, dated June 3, 2009, between RAAM Global Energy and Ram Development LLC and RAAM Exploration LLC (Incorporated by reference to Exhibit 10.13 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

10.6		September 2003 Agreement, dated September 22, 2003, between Century Exploration Company and RAAM Exploration LLC (Incorporated by reference to Exhibit 10.14 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

10.7		Participation and Exploration Agreement, dated August 3, 2009, between RAAM Global Energy Company, Century Exploration Houston, Inc. and TechXplore, L.P (Incorporated by reference to Exhibit 10.15 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

10.8		After Payout Overriding Royalty Plan of RAAM Global Energy Company and Century Exploration New Orleans, Inc., dated December 1, 2004 (Incorporated by reference to Exhibit 10.16 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on March 17, 2011 (Reg. No. 333-172897)).

10.9†		Form of Stock Purchase Agreement, effective August 24, 2011, between the Sellers defined therein and RAAM Global Energy Company (Incorporated by reference to Exhibit 10.10 to RAAM Global Energy Company’s Registration Statement on Form S-4 filed on August 29, 2011(Reg. No. 333-172897)).

10.10		Purchase Agreement, dated April 5, 2013, among RAAM Global Energy Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Century Exploration Resources, LLC and Global Hunter Securities, LLC. (Incorporated by reference to Exhibit 10.1 to RAAM Global Energy Company’s Current Report on Form 8-K filed on April 11, 2013 (File No. 333-172897)).

10.11		Forbearance Agreement, dated as of July 31, 2014, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Century Exploration Resources, LLC, RAAM Global Energy Company, Union Bank, N.A., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.8 to RAAM Global Energy Company’s Current Report on Form 8-K filed on August 5, 2014 (Reg. No. 333-172897)).

130


Exhibit Number		Description

10.12		Fifth Amended and Restated Credit Agreement, dated as of September 12, 2014, by and among RAAM Global Energy Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Century Exploration Resources, LLC and Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.8 to RAAM Global Energy Company’s Current Report on Form 8-K filed on September 16, 2014 (Reg. No. 333-172897)).

10.13*		Consent to the Fifth Amended and Restated Credit Agreement, dated as of December 29, 2014, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Century Exploration Resources, LLC, RAAM Global Energy Company and Wilmington Trust, National Association, as administrative agent and the lenders party thereto.

21.1*		Subsidiaries of RAAM Global Energy Company.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

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

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

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

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

99.1*		Summary Report of Netherland, Sewell & Associates, Inc.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

*	Filed herewith.

**	Furnished herewith.

†	Management contract or compensatory plan or arrangement.

131

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company