UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

 

 

Commission File Number: 000-50682

 

RAM Energy Resources, Inc.

(Exact name of registrant as specified in its charter)

 

 

(918) 663-2800

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $.0001 par value

 

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

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

 

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

 

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 (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

 

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 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.  o

 

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 o     No þ

 

As of March 16, 2011, there were outstanding 78,378,233 shares of registrant’s $.0001 par value common stock. Based upon the closing price for the registrant’s common stock on the NASDAQ Capital Market as of June 30, 2010, the aggregate market value of shares of common stock held by non-affiliates of the registrant was approximately $85.0 million. Documents incorporated by reference: The information called for by Part III is incorporated by reference to the definitive proxy statement for the Registrant’s 2011 annual meeting of stockholders, which will be filed with the Securities and Exchange Commission, or SEC, no later than 120 days after December 31, 2010.

 

 

RAM ENERGY RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2010

TABLE OF CONTENTS

 

 

 

Overview

 

We have included definitions of technical terms important to an understanding of our business under “Glossary of Oil and Natural Gas Terms.”

 

Unless the context otherwise requires, all references in this report to “RAM Energy Resources,” “our,” “us,” and “we” refer to RAM Energy Resources, Inc. (formerly known as Tremisis Energy Acquisition Corporation) and its subsidiaries, as a combined entity.

 

We were incorporated in Delaware on February 5, 2004. Our operations are encompassed in our wholly owned primary subsidiaries, RAM Energy, Inc. and RAM Operating Company, Inc. and their respective subsidiaries. Our executive offices are located at 5100 East Skelly Drive, Suite 650, Tulsa, Oklahoma 74135 (918) 663-2800. We also have offices in Plano and Houston, Texas.

 

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of oil and natural gas properties, primarily in Texas, Louisiana and Oklahoma. Our producing properties are located in highly prolific basins with long histories of oil and natural gas operations. We have been active in our core producing areas of Texas, Oklahoma and Louisiana since our inception in 1987 and have grown through a balanced strategy of acquisitions, development and exploratory drilling. We have completed over 24 acquisitions of producing oil and natural gas properties and related assets for an aggregate purchase price in excess of $700.0 million. Through December 31, 2010, we have drilled or participated in the drilling of 846 oil and natural gas wells, approximately 94% of which were successfully completed and produced hydrocarbons in commercial quantities. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

 

On December 8, 2010, we completed the sale to Milagro Producing, LLC, a privately owned company located in Houston, Texas, of all of our oil and natural gas properties and related assets located in the Boonsville and Newark East fields of Jack and Wise Counties, Texas. The effective date of the sale was October 1, 2010. The sale properties included all of our Bend Conglomerate shallow gas properties and all of our North Texas Barnett Shale properties, including both producing properties and undeveloped leasehold. We received net cash proceeds at closing of $42.3 million subject to customary post-closing adjustments. As of December 31, 2010, net proceeds including post-closing adjustments were $41.0 million. Proved reserves from these properties accounted for approximately 26.4 billion cubic feet equivalent (Bcfe) of natural gas, natural gas liquids and oil, or an estimated 13% of our year-end 2009 proved reserves of 204 Bcfe. Information as to our recent divestitures is set forth under Note B to the Consolidated Financial Statements.

 

Our oil and natural gas assets are characterized by a combination of developing and mature reserves and properties. We have mature oil and mature natural gas reserves located primarily in Wichita, Wilbarger and Starr Counties, Texas, Pontotoc County, Oklahoma, and in several parishes in Louisiana.

 

As of December 31, 2010, our estimated net proved reserves were 24.4 MMBoe, of which approximately 54% were crude oil, 36% were natural gas, and 10% were natural gas liquids, or NGLs. The PV-10 Value of our proved reserves was approximately $364.2 million based on benchmark prices of $79.43 per Bbl of oil and $4.38 per Mcf of natural gas. The benchmark prices reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas during each month of 2010, as required by SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting,” effective December 31, 2009. For more information regarding our PV-10 Value, including a reconciliation to the standardized measure of discounted future net cash flows relating to our estimated proved reserves, see Item 2. “Properties — Oil and Natural Gas Reserves.” At December 31, 2010, our proved developed reserves comprised 62% of our total proved reserves.

 

At December 31, 2010, we owned interests in approximately 4,100 wells and were the operator of leases upon which approximately 3,200 of these wells are located. The PV-10 Value attributable to our interests in the properties we operate represented approximately 98% of our aggregate PV-10 Value as of December 31,

2010. We also own a drilling rig, various gathering systems, a natural gas processing plant, service rigs and a supply company that service our properties.

 

During the twelve months ended December 31, 2010, we drilled or participated in the drilling of 70 wells on our oil and natural gas properties, 62 of which were successfully completed as producing wells, one of which was a dry hole well and seven of which were either drilling or waiting to be completed at the end of that period. For the twelve months ended December 31, 2010, we generated Modified EBITDA of $51.0 million from production averaging nearly 5,921 Boe per day. For more information regarding our Modified EBITDA, including a reconciliation to our net income (loss), see Item 6. “Selected Financial Data.”

 

Our Business Strategy and Strengths

 

Our primary objective is to enhance stockholder value by increasing our net asset value, net reserves and cash flow per share through acquisitions, development, exploitation, exploration and divestiture of oil and natural gas properties. Commencing June 2010, we initiated a comprehensive review of our strategic alternatives to determine the future direction of the Company. In the course of conducting this review, our development capital expenditures slowed to a lower level than originally projected. In late 2010, we decided to engage in strategic sales of certain of our non-core assets and refinance our indebtedness, as a result of which the pace of our development capital expenditures increased once again. The refinancing of our credit facility in March 2011 allows us to continue the development and exploitation of our existing properties and to pursue an increased exploration strategy while searching out selective acquisitions. As in the past, we intend to follow a balanced risk strategy by allocating capital expenditures in a combination of lower risk development and exploitation activities and higher potential exploration prospects. We intend to pursue acquisitions during periods of attractive acquisition values and emphasize development of our reserves during periods of higher acquisition values. Key elements of our business strategy include the following:

 

 

We believe that the following strengths complement our business strategy:

 

 

Glossary of Oil and Natural Gas Terms

 

The definitions set forth below apply to the indicated terms as used in this report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

 

Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

 

Bcf.  One billion cubic feet of natural gas.

 

Boe.  Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil.

 

Btu.  British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

 

Completion.  The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development well.  A well drilled within the proved areas 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 natural gas in another reservoir.

 

Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

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

 

MBbls.  One thousand barrels of crude oil or other liquid hydrocarbons.

 

MBoe.  One thousand Boe.

 

MMBoe.  One million Boe.

 

Mcf.  One thousand cubic feet of natural gas.

 

MMBbls.  One million barrels of crude oil or other liquid hydrocarbons.

 

MMBtu.  One million Btus.

 

MMcf.  One million cubic feet of 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.

 

Operator.  The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

 

PV-10 Value.  When used with respect to oil and natural gas reserves, the estimated future gross revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using the prices provided in the reserve report and costs in effect as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

 

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

 

Proved developed producing reserves.  Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

 

Proved developed reserves.  Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

 

Proved reserves.  Those quantities of oil and natural 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 estimation.

 

Proved undeveloped location.  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

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.

 

Recompletion.  The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

 

Reserve life.  A ratio determined by dividing our estimated existing reserves determined as of the stated measurement date by production from such reserves for the prior twelve month period.

 

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

 

3-D seismic.  The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

 

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.

 

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

 

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

 

FORWARD LOOKING STATEMENTS

 

This report, including information included in, or incorporated by reference from filings by us with the SEC, as well as information contained in written material, press releases and oral statements issued by us or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaning of federal securities laws that are subject to a number of risks and uncertainties, many of which are beyond our control. This report modifies and supersedes documents filed by us before this report. In addition, certain information that we file with the SEC in the future will automatically update and supersede information contained in this report. All statements, other than statements of historical fact, included or incorporated by reference in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

 

Forward-looking statements may include statements about our:

 

• business strategy;

 

• reserves;

 

• technology;

 

• financial strategy;

 

• oil and natural gas realized prices;

 

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

 

• the amount, nature and timing of capital expenditures;

 

• drilling of wells;

 

• competition and government regulations;

• marketing of oil and natural gas;

 

• property acquisitions and divestitures;

 

• costs of developing our properties and conducting other operations;

 

• general economic conditions;

 

• uncertainty regarding our future operating results; and

 

• plans, objectives, expectations and intentions contained in this report that are not historical.

 

All forward-looking statements speak only as of the date of this report, and, except as required by law, we do not intend to update any of these forward-looking statements to reflect changes in events or circumstances that arise after the date of this report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. The market data and certain other statistical information used throughout this report are based on independent industry publications, government publications or other published independent sources. Some data are also based on our good faith estimates. Although we believe these third-party sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.

 

 

We face a variety of risks that are inherent in our business and our industry, including operational, legal and regulatory risks. The following are the known, material risks that could affect our business and our results of operations.

 

Risks Related to Our Business

 

The volatility of oil and natural gas prices greatly affects our profitability.

 

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in further write-downs of the carrying values of our oil and natural gas properties as a result of our use of the full cost accounting method.

 

Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control, including:

 

 

 

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty.

 

Oil and natural gas prices could decline to a point where it would be uneconomic for us to sell our oil and natural gas at those prices, which could result in a decision to shut in production until the prices increase.

 

Our oil and natural gas properties will become uneconomic when oil and natural prices decline to the point at which our revenues are insufficient to recover our lifting costs. For example, in 2010, our average lifting costs were approximately $18.49 per Boe, or $3.08 per Mcfe. A market price decline below that price would result in our having to shut in certain production until prices increase.

 

A decline of oil and natural gas prices or a prolonged period of reduced oil and natural gas prices could result in a decrease in our exploration and development expenditures, which could negatively impact our future production.

 

We currently expect to have sufficient cash flows from operations to meet our projected non-acquisition capital expenditure needs for 2011. However, if oil and natural gas prices decline or reduce to lower levels for a prolonged period of time, we may be unable to continue to fund capital expenditures at historical levels due to the decreased cash flows that will result from such reduced oil and natural gas prices. Additionally, a decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a reduction of our borrowing base under our credit facilities, which will further reduce the availability of cash to fund our operations. As a result, we may have to reduce our capital expenditures in future years. A decrease in our capital expenditures will likely result in a decrease in our production levels.

 

Reduced development capital expenditures in 2011 could result in decreased production in 2012.

 

In 2010, our capital expenditures related to development and exploitation activities were approximately $27.9 million. For 2011, we have budgeted $23.0 million for capital expenditures related to development and exploitation activities and related geological and geophysical costs, an 18% decrease over the prior year. This anticipated decline in capital expenditures for development and exploitation activities could result in a decrease in production in 2012 and possibly beyond, unless our development and exploitation capital expenditures are subsequently increased, we find increased productive reserves through our exploration program or we acquire more production through strategic acquisitions.

 

Continued weakness in economic conditions or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.

 

U.S. and global economies and financial systems have continued to experience turmoil and upheaval characterized by extreme volatility in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions, continued high levels of unemployment, and an unprecedented level of intervention by the U.S. federal government and other governments. Although some portions of the economy appear to have stabilized or even improved and there have been signs of the beginning of recovery, the extent and timing of a recovery, and whether it can be

sustained, are uncertain. Continued weakness in the U.S. or global economies could materially adversely affect our business and financial condition. For example:

 

 

Oil prices have improved significantly in 2010 as compared to 2009 while natural gas prices continue to stagnate. Our profitability is directly related to the prices we receive for the sale of the oil and natural gas we produce. In early July 2008, commodity prices reached record levels in excess of $140.00 per barrel for crude oil and $13.00 per Mcf for natural gas. The 2008 year ended with market prices dropping to $44.00 for crude oil and $4.00 for natural gas, a 69% to 73% decline from the earlier highs. During 2009, market prices ended at a high of approximately $72.00 for crude oil and $4.00 for natural gas. As of December 31, 2010, crude oil prices continued to rise to approximately $87.00 while natural gas prices remained constant at approximately $4.00.

 

Our success depends on acquiring or finding additional reserves.

 

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we must commence exploratory drilling, undertake other replacement activities or utilize third parties to accomplish these activities. There can be no assurance, however, that we will have sufficient resources to undertake these actions, that our exploratory projects or other replacement activities will result in significant additional reserves or that we will succeed in drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

 

In accordance with customary industry practice, we rely in part on independent third party service providers to provide most of the services necessary to drill new wells, including drilling rigs and related equipment and services, horizontal drilling equipment and services, trucking services, tubular goods, fracing and completion services and production equipment. The oil and natural gas industry has experienced significant volatility in cost for these services in recent years and this trend is expected to continue into the future. Any future cost increases could significantly increase our development costs and decrease the return possible from drilling and development activities, and possibly render the development of certain proved undeveloped reserves uneconomical.

 

The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.

 

This report and other SEC filings by us contain estimates of our proved oil and natural gas reserves and the estimated future net revenues from those reserves. These estimates are based on various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, timing of operations, and availability of funds. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent on many variables, and therefore changes often occur as these variables evolve.

Therefore, these estimates are inherently imprecise. For example, total revisions of our previous reserve estimates decreased proved reserves by 3.3 MMBoe or approximately 10% of our reserves at the beginning of the year. The revisions included a positive increase of 1.8 MMBoe or 5% of the beginning of the year reserves caused by higher oil and gas prices. This positive revision was offset by the downward revision of 1.1 MMBoe caused by the transfer of proved undeveloped to unproved categories as a result of changes to the company development plans during 2010, and 4.0 MMBoe of the downward revisions were mostly due to changes in well performance in our gas properties in South Texas.

 

Actual future production, oil and natural gas prices, revenues, production taxes, development expenditures, operating expenses, and quantities of producible oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of and present values related to proved reserves disclosed by us, and the actual quantities and present values may be less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activity, prevailing oil and natural gas prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties.

 

As of December 31, 2010, approximately 38%, or 9.2 MMBoe, of our estimated proved reserves were proved undeveloped, and approximately 7%, or 1.7 MMBoe, were proved developed non-producing. In order to develop our proved undeveloped reserves, we estimate approximately $101.8 million of capital expenditures will be required. Production revenues from proved developed non-producing reserves will not be realized until sometime in the future and after some investment of capital. In order to bring production on-line for our proved developed non-producing reserves, we estimate capital expenditures of approximately $8.3 million will be required. The estimated abandonment costs associated with our Louisiana production facilities make up the balance of our anticipated capital expenditures. Although we have estimated our reserves and the costs associated with these reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.

 

You should not assume that the PV-10 Value and standardized measure of discounted future net cash flows included in this report represent the current market value of our estimated proved oil and natural gas reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. For example, our proved reserves and PV-10 Values as of December 31, 2010, were estimated using the 12-month unweighted arithmetic average of the first-day-of-the-month price of $79.43 per Bbl of oil (NYMEX West Texas Intermediate settle price) and $4.38 per Mcf of natural gas (Platts Henry Hub spot price). We then adjust these base prices to reflect appropriate basis, quality, and location differentials over that period in estimating our proved reserves. During 2010, our monthly average realized oil prices, excluding the effect of hedging, were as high as $86.84 per Bbl and as low as $71.92 per Bbl. For the same period, our monthly average realized natural gas prices before hedging were as high as $5.72 per Mcf and as low as $3.27 per Mcf. Many other factors will affect actual future net cash flows, including:

 

 

The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10 Values. In addition, the ten percent discount factor required by the SEC to be used to calculate PV-10 Values for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and natural gas industry in general are subject.

We expect to obtain a substantial portion of our funds for property acquisitions and for the drilling and development of our oil and natural gas properties through a combination of cash flows from operations and borrowings. If such borrowed funds were not available to us, or if the terms upon which such funds would be available to us were unfavorable, our ability to acquire oil and natural gas properties, the further development of our oil and natural gas reserves, and our financial condition and results of operations, could be adversely affected.

 

We expect to fund a substantial portion of our future property acquisitions and our drilling and development operations with a combination of cash flows from operations and borrowed funds. To the extent such borrowed funds are not available to us at all, or if the terms under which such funds would be available to us would be unfavorable, our ability to acquire oil and natural gas properties and the further development of our oil and natural gas reserves could be adversely impacted. In such events, we may be unable to replace our reserves of oil and natural gas which, subsequently, could adversely affect our financial condition and results of operations.

 

The continued tightness in the financial and credit markets may expose us to counterparty risk with respect to our sales of oil and natural gas.

 

We sell our crude oil, natural gas and natural gas liquids to a variety of purchasers. Some of these parties may not be as creditworthy as we are and may experience liquidity problems. Nonperformance by a trade creditor could result in our incurring losses.

 

Operating hazards and uninsured risks may result in substantial losses.

 

Our operations are subject to all of the hazards and operating risks inherent in drilling for, and the production of, oil and natural gas, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks. There can be no assurance that any insurance will be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase. In addition, we may be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities would not be covered by our insurance.

 

Our operations are subject to various governmental regulations that require compliance that can be burdensome and expensive.

 

Our operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge from drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. These laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management, and compliance with these laws may cause delays in the additional drilling and development of our properties. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. While historically we have not experienced any material adverse effect from regulatory delays, there can be no assurance that such delays will not occur in the future.

Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.

 

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Texas, Louisiana and Oklahoma, our operations are constantly at risk of extreme adverse weather conditions such as hurricanes and tornadoes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as hurricanes or floods, whether due to climate change or otherwise.

 

Climate change and government laws and regulations related to climate change could negatively impact our financial condition.

 

In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and may, directly or indirectly, be affected by government laws and regulations related to climate change. We cannot predict with any degree of certainty what effect, if any, possible climate change and new and developing government laws and regulations related to climate change will have on our operations, whether directly or indirectly. While we believe that it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect, directly or indirectly, (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, and (v) the cost of utility services, particularly electricity, in connection with the operation of our properties. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.

 

Regulation and recent court decisions related to greenhouse gas emissions could have an adverse effect on our operations and demand for oil and natural gas.

 

The U.S. Congress has previously considered legislation to reduce emissions of “greenhouse gases,” including carbon dioxide, methane and nitrous oxide among others, which some studies have suggested may be contributing to warming of the earth’s atmosphere. However, legislation to reduce greenhouse gases appears less likely in the near term. As a result, near term regulation of greenhouse gases, if any, is more likely to come from regulatory action by EPA or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.

 

As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, 549 U.S. 497 (2007), finding that greenhouse gases fall within the Clean Air Act (“CAA”) definition of “air pollutant,” the Environmental Protection Agency (“EPA”) was required to determine whether emissions of greenhouse gases “endanger” public health or welfare. As a result, the EPA has adopted regulations requiring Clean Air Act (“CAA”) permitting of greenhouse gas emissions from stationary and mobile sources. On December 15, 2009, EPA promulgated its final rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” finding that (i) the current and projected emissions of six key well-mixed greenhouse gases, including carbon dioxide and methane, constitute a threat to public health and welfare, and (ii) the combined emissions from motor vehicles cause and contribute to the climate change problem which threatens public health and welfare. These findings did not themselves impose any requirements on industry or other entities, but were a prerequisite to EPA’s adoption of greenhouse gas

emission standards for motor vehicles. On May 7, 2010, EPA and the Department of Transportation’s National Highway Traffic and Safety Administration, or NHTSA, promulgated a final action establishing a national program providing new standards for certain motor vehicles to reduce greenhouse gas emissions and improve fuel economy, with EPA adopting the standards under the CAA, and NHTSA adopting the standards as Corporate Average Fuel Economy standards under the Energy Policy and Conservation Act. While these motor vehicle regulations do not directly impact oil and natural gas production operations, the result of these actions are significant in that they automatically trigger application of certain CAA permit programs for stationary greenhouse gas emissions sources, potentially including oil and natural gas production operations. These programs, the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs, have historically applied to sources of air pollutants “subject to regulation” with emissions exceeding 100 and 250 tons per year. To avoid the broad impact of such low permitting thresholds for greenhouse gas emission sources, on June 3, 2010, EPA promulgated its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” to add new higher thresholds of 75,000 tons per year carbon dioxide equivalents (“CO₂e”) for modifications and 100,000 tons per year CO₂e for new sources.

 

Additionally, EPA has promulgated separate regulations requiring greenhouse gas emission reporting from certain industry sectors, including natural gas production. On October 30, 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in developing policy approaches to greenhouse gas regulation. This reporting rule became effective on December 29, 2009. On November 30, 2010, EPA promulgated additional mandatory greenhouse gas reporting rules that apply specifically to oil and natural gas production for implementation in 2011.

 

Though under review by the D.C. Circuit, EPA’s rules promulgated thus far have survived petitions for stay, and are currently final and effective, and will remain so unless vacated or remanded by the court, or unless Congress adopts legislation preempting EPA’s regulatory authority to address greenhouse gases under the CAA.

 

Beyond legislative and regulatory developments, there have been several recent court cases impacting this area of risk related to greenhouse gas emissions. The final decisions in these cases may expose us to similar litigation risk.

 

The decisions in these cases may expose us, as potentially an emitter of significant direct and indirect emission sources of greenhouse gases, to similar litigation risk.

 

International treaties. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Though the 16th meeting of the Council of the Parties in Mexico in November and December 2010 did not produce a legally binding final agreement, international negotiations continue, with the participation of the United States.

 

International developments, passage of state or federal climate control legislation or other regulatory initiatives, the implementation of regulations by EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or further development of case law allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and financial condition as a result of material increases in operating and production costs and litigation expense due to expenses associated with monitoring, reporting, permitting and controlling greenhouse gas emissions or litigating claims related to emissions of greenhouse gases, and the demand for oil and natural gas and increase the costs of our operations.

 

Potential legislative and regulatory actions relating to Federal income taxation and derivatives trading could increase our costs, reduce our revenue and cash flow from oil and natural gas sales, reduce our liquidity or otherwise alter the way we conduct our business.

 

In 2009, 2010 and 2011, the administration of President Obama made budget proposals which, if enacted into law by Congress, would potentially increase and accelerate the payment of federal income taxes by

independent producers of oil and natural gas. Proposals have included, but have not been not limited to, repealing the expensing of intangible drilling costs, repealing the deduction for the cost of qualified tertiary expenses, repealing the exception to the passive loss limitation for working interests in oil and natural gas properties, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and natural gas companies, and increasing the amortization period of geological and geophysical expenses. In 2009 and 2010, legislation which would have implemented the proposed changes was introduced but not enacted. It is unclear whether legislation supporting any of the above described proposals, or designed to accomplish similar objectives, will be introduced or, if introduced, would be enacted into law or, if enacted, how soon resulting changes would become effective. However, the passage of any legislation designed to implement changes in the U.S. federal income tax laws similar to the changes included in the budget proposals offered by the White House in 2009, 2010 and 2011 could eliminate certain tax deductions currently available with respect to oil and gas exploration and development, and any such changes (i) could make it more costly for us to explore for and develop our oil and natural gas resources and (ii) could negatively affect our financial condition and results of operations. On July 21, 2010, the President signed into law the “Wall Street Transparency and Accountability Act of 2010” (the “WSTA Act”) which directs the Federal Reserve to create uniform standards for the management of certain risks associated with, among other things, the trading of certain derivatives over the counter (“OTC”). In recent years, we have maintained an active price and basis protection hedging program related to the oil and natural gas we produce. Additionally, we have used the OTC market exclusively for our oil and natural gas derivative contracts and have relied on our hedging activities to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. While the manner in which the Federal Reserve will implement the directives contained in the WSTA Act is unclear, we anticipate such implementation may include the imposition of clearing and standardization requirements for all derivatives currently traded on the OTC and could restrict trading positions in the energy futures markets. While the ultimate impact on us of such changes, if implemented, is unclear, we anticipate they may materially reduce our hedging opportunities and could negatively affect our revenues and cash flow during periods of low commodity prices.

 

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

We utilize hydraulic fracturing as a means to enhance the productive capability of our wells. Congress has previously considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills previously proposed before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. That proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptions for hydraulic fracturing from the Safe Drinking Water Act. These legislative efforts have halted while EPA studies the issue of hydraulic fracturing in 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced water. These developments, as well as increased scrutiny of hydraulic fracturing activities by state authorities, may result in additional levels of regulation or level of complexity with respect to existing regulation at the federal and state levels that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing, which could result in limiting the productive capability of future wells in which we likely would utilize hydraulic fracturing and increase our costs of compliance and doing business.

We may not be able to borrow the full amount of the borrowing base under our revolving credit facilities because of the amount of our Modified EBITDA. The inability to fully borrow funds up to our borrowing base could reduce our capital expenditures.

 

As of December 31, 2010, our borrowing base under our old revolving credit facility was $145.0 million. As of the same date, we had outstanding advances under the revolving credit facility of $116.5 million, leaving an aggregate availability under our revolver of $28.5 million. However, because of the amount of our Modified EBITDA, the financial covenants set forth in our old credit facility would have limited us to additional borrowings under our revolving credit facility as of December 31, 2010, of $23.7 million. On March 14, 2011, we entered into a new revolving credit facility with a borrowing base of $150.0 million. Based on our Modified EBITDA for the four fiscal quarters ending December 31, 2010, our borrowings would not have been limited under the new revolving credit facility. Should our Modified EBITDA decline, we may be unable to borrow funds up to the full amount of our borrowing base. Our inability to borrow the full amount of our borrowing base under our revolving credit facility could reduce our current year capital expenditures if we do not meet our goal of funding our 2011 capital expenditures from our operating cash flow.

 

Our method of accounting for investments in oil and natural gas properties may result in a further impairment of asset value, which could affect our stockholder equity and net profit or loss.

 

We use the full cost method of accounting for our investment in oil and natural gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves are capitalized into a “full cost pool.” Capitalized costs in the pool are amortized and charged to operations using the units-of-production method based on the ratio of current production to total proved oil and natural gas reserves. To the extent that such capitalized costs, net of amortization, exceed the after tax present value of estimated future net revenues from our proved oil and natural gas reserves (using a 10% discount rate) at any reporting date, such excess costs are charged to operations. We incurred no impairment charge for 2010. In 2009, we recorded a $47.6 million charge for the impairment of our oil and natural gas properties. This amount was in addition to the $269.4 million charge we recorded in 2008. These writedowns are not reversible at a later date, even if the present value of our proved oil and natural gas reserves increases as a result of an increase in oil or natural gas prices. Further price declines could result in additional impairments of asset value.

 

Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain protection from sellers against them.

 

As part of our business strategy, we continually seek acquisitions of oil and natural gas properties. The successful acquisition of oil and natural gas properties requires assessment of many factors, which are inherently inexact and may be inaccurate, including the following:

 

 

Our assessment will not necessarily reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. With respect to properties on which there is current production, we may not inspect every well location, potential well location or pipeline in the course of our due diligence. Inspections may not reveal structural and environmental problems such as pipeline corrosion or groundwater contamination. We may not be able to obtain or recover

on contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

 

We face intensive competition in our industry.

 

We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies, many of whom have financial and other resources substantially in excess of those available to us. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation.

 

Our use of derivative contracts is subject to risks that our counterparties may default on their contractual obligations to us and may cause us to forego additional future profits or result in our making cash payments.

 

Our use of derivative contracts could have the effect of reducing our revenues and the value of our common stock. To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and will in the future enter into derivative contracts for a portion of our oil and natural gas production. Our derivative contracts are subject to mark-to-market accounting treatment, which means that the change in the fair market value of these instruments is reported as a non-cash item in our statement of operations each quarter, which typically result in significant variability in our net income. Derivative contracts expose us to the risk of financial loss and may limit our ability to benefit from increases in oil and natural gas prices in some circumstances, including the following:

 

 

The ultimate settlement amount of these unrealized derivative contracts is dependent on future commodity prices. We may incur significant unrealized losses in the future from our use of derivative contracts to the extent market prices increase and our derivatives contracts remain in place. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” appearing elsewhere in this report.

 

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

 

Our ability to make payments on our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash from operations and other resources in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas.

 

Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. None of these remedies may, if necessary, be effected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, which could cause us to default on our obligations and could impair our liquidity.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

 

Our credit agreements contain a number of significant covenants that, among other things, restrict our ability to:

 

 

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit agreements. Also, our credit agreements require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. A decline in oil and natural gas prices, or a prolonged period of oil and natural gas prices at lower levels, could eventually result in our failing to meet one or more of the financial covenants under our credit facilities, which could require us to refinance or amend the facilities resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

 

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit agreements. A default under our credit agreements, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit agreements. The accelerated debt would become immediately due and payable. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

 

Risks Related to Our Common Stock

 

We do not currently pay dividends on our common stock and do not anticipate doing so in the future.

 

We intend to retain any future earnings to fund our operations; therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Also, our credit facilities do not permit us to pay dividends on our common stock.

 

Substantial stock ownership by our executive officers, directors and other affiliates may limit the ability of our non-affiliate stockholders to influence the outcome of director elections and other matters requiring stockholder approval.

 

Persons who are our officers and directors beneficially own approximately 18% of our outstanding common stock. Accordingly, our insiders will have significant influence in the election of our directors and,

therefore, our policies and direction. This concentration of voting power could have the effect of delaying or preventing a change in our control or discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the market price for their shares of common stock.

 

You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock, which could have an adverse effect on our stock price.

 

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders. We are currently authorized to issue 100,000,000 shares of common stock and 1,000,000 shares of preferred stock with such designations, preferences and rights as determined by our board of directors. As of December 31, 2010, we had outstanding 78,386,983 shares of common stock. In addition, we have reserved an additional 1,960,271 shares for future issuance to our directors, officers and employees as restricted stock or stock option awards pursuant to our 2006 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with future acquisitions, future issuances of our securities for capital raising purposes or for other business purposes. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

 

Certain provisions of Delaware law, our certificate of incorporation and bylaws could hinder, delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

 

Certain provisions of Delaware law, our certificate of incorporation and bylaws could have the effect of discouraging, delaying or preventing transactions that involve an actual or threatened change in control of our company. Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. In addition, our certificate of incorporation and bylaws include the following provisions:

 

 

 

We could issue shares of preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects.

 

We are authorized to issue up to 1,000,000 shares of preferred stock, which shares may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions thereof, if any, of each such series of our preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and Delaware law, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series of our preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock.

 

In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving our control by the current stockholders.

 

 

None.

 

 

As we concentrate our holdings into areas that align with our objectives, we have determined to report our operations by state. Our principal properties in Texas primarily consist of the Electra/Burkburnett fields in Wichita and Wilbarger Counties and the La Copita field in Starr County. Our principal Oklahoma properties are the Northeast Fitts and Allen fields in Pontotoc and Seminole Counties. In Louisiana, our most significant property is the Lake Enfermer field in Lafourche Parish. During 2010, we drilled 62 gross wells (54.0 net) that were capable of production and experienced a success rate of 99%.

 

The following table summarizes our estimated proved oil and gas reserves by area as of December 31, 2010, and our average daily production by area for calendar year 2010:

 

 

Texas Fields

 

The average daily production from our Texas fields was 3,893 Boe per day (66% of our total daily production) in 2010, a decrease of 15% over the previous year due to natural production declines not offset by

increased drilling. We drilled a total of 58 gross (51.1 net) wells in our Texas fields, all of which were completed as wells capable of production. An additional three gross (3.0 net) wells were drilled to their objective depth and awaiting completion or pipeline connection at year end. As of December 31, 2010, the proved reserves in our Texas fields were 14.2 MMBoe and account for 58% of our total proved reserves. Our most significant Texas fields are as follows:

 

Electra/Burkburnett Fields.  We drilled a total of 48 gross (48.0 net) wells during 2010 in our Electra/Burkburnett fields in Wichita and Wilbarger Counties, Texas and have drilled more than 347 wells in these fields since November 1, 2004. We have budgeted $8.0 million in 2011 to continue development of this field. We own our own drilling rig and pulling units deployed exclusively for operations in these fields, and employ approximately 91 field personnel. We continue to focus on reducing operating costs in these fields and are also working to improve production performance through recompletions, workovers and improved water injection performance. As of December 31, 2010, the estimated proved reserves in these fields were 6.6 MMBoe (27% of our total proved reserves).

 

South Texas.  During 2010, our net daily production from our South Texas properties averaged 1,355 Boe per day and make up 27% (6.6 MMBoe) of our total proved reserves. We drilled six gross (5.8 net) wells in our La Copita field in Starr County, Texas during 2010. All completions were successful with initial production rates up to 482 Boe per day from the Vicksburg formation. We are the operator of all of the wells in our La Copita field. Due to continued low natural gas prices, we have allocated only $2.0 million of our 2011 non-acquisition capital budget to South Texas.

 

Oklahoma Fields

 

We produced an average of 1,296 Boe per day (22% of our total daily production) from our Oklahoma fields in 2010, a decrease of 19% over the previous year primarily due to natural production declines and weather-related interruptions. We drilled a total of three gross (2.9 net) wells in our Oklahoma fields, all of which were completed as wells capable of production. An additional three gross (2.8 net) wells were drilled to their objective depth and awaiting completion or pipeline connection at year end. As of December 31, 2010, the proved reserves in our Oklahoma fields were 6.3 MMBoe and account for 26% of our total proved reserves. Our most significant Oklahoma fields are as follows:

 

Northeast Fitts and Allen Fields.  During 2010, we initiated the drilling of 3 gross (2.7 net) development wells in our Northeast Fitts unit in Pontotoc County, Oklahoma. No wells were drilled during 2009 in our Allen field of Pontotoc and Seminole Counties. The Northeast Fitts field produces from shallow McAlester and Hunton formations at depths less than 4,000 feet. We are the operator of the units and, as such, control the pace of operations. The majority of our value in the Northeast Fitts field is primarily a mature waterflood. Our Allen Field has future behind-pipe and undeveloped opportunities in shallow multi-pay reservoirs. The combined proved reserves from these two areas are 5.6 MMBoe (23% of our total proved reserves). We have budgeted $2.0 million for development costs in our Northeast Fitts and Allen fields in 2010.

 

Louisiana Fields

 

The average daily production from our Louisiana fields was 532 Boe per day (9% of our total daily production) in 2010, a decrease of 6% over the previous year due to natural production declines. We drilled a total of one gross (0.2 net) wells in our Louisiana fields, which was non-productive. As of December 31, 2010, the proved reserves in our Louisiana fields were 3.2 MMBoe and account for 13% of our total proved reserves.

The following table summarizes our 2010 drilling activity:

 

 

 

 

Development, Exploitation and Exploration Programs

 

Development and Exploitation Program.  Our future production and performance depends to a large extent on the successful development of our existing reserves of oil and natural gas. We have identified multiple development projects on our existing properties (substantially all of which are located in our core areas), and these projects involve both the drilling of development wells and extension wells. We are the operator of leases covering approximately 2,500 of the wells capable of production in which we own interests, and as such we are able to control expenses, capital allocation and the timing of development activities on these properties. We also own interests in, and operate, approximately 700 injection wells. During the year ended December 31, 2010, we drilled or participated in the drilling of 62 gross (54.0 net) development wells capable of production. Capital expenditures in connection with these activities during this period aggregated approximately $27.9 million.

 

Another determinant of future performance is the exploitation of existing wells that can be recompleted or otherwise reworked to extract additional hydrocarbons. We have identified approximately 45 operated projects involving recompletions in existing wells that we operate, all of which involve reserves included in our proved reserves at December 31, 2010.

 

Exploration Program.  Historically, an important component of our strategy to expand our reserves and production has been an active exploration program focused on adding long-lived oil and natural gas reserves from our core areas and other resource plays. We have obtained a concession in Osage County, Oklahoma on over 56,000 acres with 100% working interest. We have 3-D seismic data covering approximately 16,000 acres and have obtained permits for shooting approximately 20,000 additional acres. During 2011, assuming the continuation of existing commodity prices for oil and natural gas, we expect to conduct only limited exploratory drilling, primarily on our Osage concession.

 

We have an experienced technical staff, including geologists, landmen, engineers and other technical personnel devoted to prospect generation and identification of potential drilling locations. We seek to reduce exploration risk by exploring at moderate depths that are deep enough to discover sizeable oil and natural gas accumulations (generally less than 13,000 feet). Our established presence in our core areas has provided our staff with substantial expertise. Many of our exploration plays are based upon seismic data comparisons to our existing producing fields. For exploration prospects we generate, we typically will own a greater interest in these projects than our drilling partners, if any, and will operate the wells. As a result, we will be able to influence the areas of exploration and the acquisition of leases, as well as the timing and drilling of each well.

 

During the year ended December 31, 2010, we participated in the drilling of four gross (3.2 net) exploratory wells. For 2011, we have budgeted $8.0 million for geological and geophysical activities relating to exploitation and exploration projects and $9.0 million for exploration, including leasehold acquisition, seismic and exploratory drilling. We are encouraged by the results of our Osage concession exploratory project in 2010 and plan to increase our spending in 2011.

Oil and Natural Gas Reserves

 

Our proved reserve estimates for crude oil and natural gas were prepared by Forrest A. Garb & Associates, an independent petroleum engineering firm, in accordance with the generally accepted petroleum engineering and evaluation principles and most recent definitions and guidelines established by the Securities and Exchange Commission (“SEC”). A copy of Forrest A. Garb & Associates’ summary reserve report is attached as an exhibit to this report. All reserve definitions comply with the definitions of Rules 4-10 (a) (1)-(32) of SEC Regulation S-X.

 

To determine our estimated proved reserves, and as required by the SEC, we used the 12-month unweighted arithmetic average of the first-day-of-the-month price for the months of January through December 2010 calculated to be $4.38 per Mcf of natural gas and $79.43 per Bbl of oil. These prices were held constant for the life of the properties and adjusted for the appropriate market differentials.

 

As of December 31, 2010, our proved crude oil and natural gas reserves and PV-10 Value are presented below by reserve category. All of our proved reserves are located within the United States.

 

 

Our properties have a 13.7 year reserve-to-production ratio.

 

Proved Undeveloped Reserves

 

At December 31, 2010, our total proved undeveloped reserves were 9.2 MMBoe, comprised of 5.6 MMBbl of crude oil and natural gas liquids and 21.8 Bcf of natural gas. As a result of our 2010 development activities, we converted approximately 760 MBoe, or 5%, of our 2009 proved undeveloped reserves to proved developed. The capital costs to develop these reserves were approximately $13.0 million. Also during 2010, we drilled wells at 40 locations that did not include proved reserves as of December 31, 2009. We did not add any new proved undeveloped locations during 2010. Our projected costs to develop our remaining proved undeveloped reserves are $16.3 million in 2011, $36.0 million in 2012, $22.0 million in 2013, $15.7 million in 2014 and $11.8 million in 2015.

 

Unproved Reserves

 

The new SEC guidelines allow for the disclosure of probable and possible reserves, which are unproved reserves. Disclosure of unproved reserves is optional and we have elected not to disclose any unproved reserves in this report.

 

Technologies Used to Establish Additions to Reserve Estimates

 

The revised rules permit the use of reliable technologies that have been field tested as evidence proven to establish with “reasonable certainty” quantities of proved reserves. They also permit assigning reserves to locations more than one offset away from standard development spacing if reasonable certainty can be established, and the estimates are economically producible. We evaluated the potential use of reliable technologies in connection with the preparation of our 2010 reserve estimates and have elected not to rely on the new rule as a means of assigning proved or unproved reserves. We are, however, actively using seismic interpretation to high grade our potential drilling locations. In future filings, we may use reliable technologies to assign reserves if the application can prove with a high degree of confidence that the estimated quantities can be recovered.

Internal Controls over Reserves Estimate

 

Our policies regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with SEC regulations. Responsibility for compliance in reserve bookings is delegated to our reservoir engineering group, which is led by our Senior Vice President of Operations.

 

Technical reviews are performed throughout the year by our engineering and geologic staff who evaluate pertinent geological and engineering data. This data in conjunction with economic data and ownership information is used in making a determination of proved reserve quantities. The reserve process is overseen by our Vice President of Business Development. Our internal reservoir engineering staff has an average experience of more than 20 years in the area of reserve estimating and reservoir evaluations. We have internal auditing guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. Technologies and economic data used include updated production data, well performance, formation logs, geological maps, reservoir pressure tests and wellbore mechanical integrity information. Final approval of the reserves is required by our Senior Vice President of Operations.

 

Our reserve estimates are certified by the independent petroleum engineering firm of Forrest A. Garb & Associates using their own engineering assumptions and the economic data which we provide. Forrest A. Garb & Associates is an independent petroleum engineering consulting firm that provides petroleum consulting services throughout the world. Forrest A. Garb is chairman of the board of his firm, and is a registered professional engineer with more than 50 years of practical petroleum industry experience. The Forrest A. Garb & Associates report is included as Exhibit 99.1.

 

In addition to third party reserve report preparation, our reserves are reviewed by senior management and the Audit Committee of our Board of Directors. Senior management, which includes the President and Chief Executive Officer, the Senior Vice President of Operations and the Senior Vice President and Chief Financial Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews the final reserves estimate in conjunction with Forrest A. Garb & Associates’ certified reserve report letter. They may also meet with the key representative from Forrest A. Garb & Associates to discuss their process and findings.

 

Estimated quantities of proved reserves and future net revenues are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the control of the producer. The reserve data set forth in this report represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revisions based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors, which revisions may be material. The PV-10 Value of our proved oil and natural gas reserves does not necessarily represent the current or fair market value of such proved reserves, and the 10% discount factor may not reflect current interest rates, our cost of capital or any risks associated with the development and production of our proved oil and natural gas reserves. Proved reserves include proved developed and proved undeveloped reserves.

Reserve Reconciliation

 

Our total proved reserve reconciliation starting at year-end 2009 and ending year-end 2010 is as follows:

 

 

 

 

Our proved developed reserves, total proved reserves, estimated PV-10 Value and prices used after the effects of market differentials by year are as follows:

 

 

The prices used in calculating the PV-10 values are net of the appropriate market differentials and are for the economic life of the properties.

 

The following is a summary of the standardized measure of discounted net cash flows using methodology provided for in Topic 932 of the Accounting Standards Codification^tm (the “Codification”) implemented by the Financial Accounting Standards Board (“FASB”), related to our estimated proved oil and natural gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves for the years ended December 31, 2010 and 2009, were computed using benchmark prices based on the unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas during each month of 2010, as required by SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting,” effective December 31, 2009, while estimated cash flows in the reserve reports at December 31, 2008, were based on oil and natural gas spot prices as of the end of the period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income tax expenses were calculated by applying future statutory tax rates (based on the current tax law adjusted for permanent differences and tax credits) to the estimated future pretax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved. Future income tax expenses increased in 2010 because net operating loss carryforward was used to offset capital gains realized in the property divestitures and also due to a decrease in net operating loss carryforwards related to Internal Revenue Code Section 382 limitation by approximately $17.0 million net operating loss adjustment, leaving less net operating loss carryforward available for future years. Additionally, future development costs are less than the previous year. For further information regarding the standardized measure of discounted net cash flows related to our estimated proved oil and natural gas reserves for the years ended December 31, 2010, 2009 and 2008, please review Note M in the notes to our year-end 2010 financial statements appearing elsewhere in this report. The standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves at December 31 is summarized as follows:

 

 

We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves as of the specified dates.

The following table provides a reconciliation of our PV-10 Value to our standardized measure:

 

 

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves.

 

Net Production, Unit Prices and Costs

 

The following table presents certain information with respect to our oil and natural gas production and prices and costs attributable to all oil and natural gas properties owned by us for the periods shown. Average realized prices reflect the actual realized prices received by us, before and after giving effect to the results of our derivative contracts. Our derivative contracts are financial, and our production of oil, natural gas and NGLs, and the average realized prices we receive from our production, are not affected by our derivative contracts.

 

Fields containing 15% or more of total proved reserves at December 31, 2010:

 

 

 

Acquisition, Development and Exploration Capital Expenditures

 

The following table presents information regarding our net costs incurred in our acquisitions of proved and unproved properties, and our development and exploration activities (in thousands):

 

 

Finding Costs

 

The following table sets forth the estimated proved reserves we acquired or discovered, including revisions of previous estimates, during each stated period. In calculating finding costs, we include acquisition costs related to proved property acquisitions, development costs, and exploration costs with respect to

exploratory wells drilled and completed. Most of our drilling in 2010 was in our mature fields on proved undeveloped properties, which does not result in significant reserve additions. Because in 2010 we had no significant acquisitions of producing properties, discoveries were limited and no significant reserves were added, our finding cost in 2010 was substantially greater per Boe as compared to prior years. Our three-year average finding cost was $15.62 per Boe.

 

 

Producing Wells

 

The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2010. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline connections or connection to production facilities. Wells that we complete in more than one producing horizon are counted as one well.

 

 

Acreage

 

The following table sets forth our developed and undeveloped gross and net leasehold acreage as of December 31, 2010:

 

 

Approximately 44% of our net acreage was located in our core areas as of December 31, 2010. Our undeveloped acreage includes leased acres 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 or not such acreage is held by production or contains proved reserves. A gross acre is an acre in which we own an interest. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres.

Drilling Activities

 

During the periods indicated, we drilled or participated in drilling the following wells:

 

 

 

 

Divestitures

 

On December 8, 2010, we completed the sale to Milagro Producing, LLC, a privately owned company located in Houston, Texas, of all of our oil and natural gas properties and related assets located in the Boonsville and Newark East fields of Jack and Wise Counties, Texas. The effective date of the sale was October 1, 2010. The sale properties included all of our Bend Conglomerate shallow gas properties and all of our North Texas Barnett Shale properties, including both producing properties and undeveloped leasehold. We received net cash proceeds at closing of $42.3 million subject to customary post-closing adjustments. As of December 31, 2010, net proceeds including post-closing adjustments were $41.0 million. Proved reserves from these properties accounted for approximately 26.4 billion cubic feet equivalent (Bcfe) of natural gas, natural gas liquids and oil, or an estimated 13% of our year-end 2009 proved reserves of 204 Bcfe.

 

On December 30, 2010, we closed the sale of certain non-operated natural gas properties located in eastern Oklahoma for $8.0 million (prior to closing adjustments). The effective date of the sale was December 1, 2010. Our full cost pool at December 31, 2010 was reduced by the net proceeds, including closing adjustments, of $7.8 million in accordance with the full cost method of accounting. The proceeds were used to reduce outstanding borrowings under our revolving credit facility.

 

Oil and Natural Gas Marketing and Derivative Activities

 

During the year ended December 31, 2010, Shell Trading (US) Company, or STUSCO, accounted for $68.1 million, or 61%, of our oil and natural gas revenue for that period. No other purchaser accounted for 10% or more of our oil and natural gas revenue during 2010. Our agreement with STUSCO covers all of our North Texas oil production. Effective August 1, 2008 through January 31, 2009, our agreement provided for payment, on a per barrel basis, of a price equal to STUSCO’s posted price for North Texas Sweet plus a premium of $3.25. Effective during the period February through June 2009, our contract price was revised to STUSCO North Texas Sweet, plus or minus Platt’s P-Plus Posting, minus $1.50. (Note: the P-Plus posted price is a fluctuating premium based on the NYMEX front-month, second-month, and third-month rolls. Shifts in the NYMEX forward curve are relative to fundamental market conditions such as petroleum stock levels at

Cushing and refinery demand.) For the period July 2009 through June 2010, our contract price was revised to STUSCO’s posted price for West Texas Intermediate (WTI) plus $0.80. Effective for the period of July through December 2010, the contract price was renegotiated to STUSCO WTI plus $1.30.

 

We are also subject to a crude purchase contract with STUSCO covering all of our oil production in our Fitts and Allen fields in Oklahoma. Effective January through February 2010, our contract price was Sunoco’s posted price for Oklahoma Sweet plus $0.25. Effective March through June 2010, our contract price increased to Sunoco OK Sweet plus $0.85, and effective July through December 2010, our price was renegotiated to Sunoco OK Sweet plus $1.15.

 

There are other purchasers in the fields and such other purchasers would be available to purchase our production should our current purchaser discontinue operations. We have no reason to believe that any such cessation is likely to occur.

 

To reduce exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow, we periodically utilize various derivative strategies to manage the price received for a portion of our future oil and natural gas production. Our derivative strategies customarily involve the purchase of put options to provide a price floor for our production, put/call collars that establish both a floor and a ceiling price to provide price certainty within a fixed range, call options that establish a secondary floor above a put/call collar ceiling, or swap arrangements that establish an index-related price above which we pay the derivative counterparty and below which we are paid by the derivative counterparty. These contracts allow us to predict with greater certainty the effective oil and natural gas prices to be received for our production and benefit us when market prices are less than the base floor prices or swap prices under our derivative contracts. However, we will not benefit from market prices that are higher than the ceiling or swap prices in these contracts for our hedged production.

 

See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further information about our derivative positions at December 31, 2010.

 

Competition

 

The oil and natural gas industry is highly competitive. We compete for the acquisition of oil and natural gas properties, primarily on the basis of the price to be paid for such properties, with numerous entities including major oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well-established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

 

Title to Properties

 

We believe that we have satisfactory title to our properties in accordance with standards generally accepted in the oil and natural gas industry. As is customary in the oil and natural gas industry, we make only a cursory review of title to farmout acreage and to undeveloped oil and natural gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect title defects, we, rather than the seller of the undeveloped property, typically are responsible to cure any such title defects at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We have obtained title opinions or reports on substantially all of our producing properties. Prior to completing an acquisition of producing oil and natural gas leases, we perform a title review on a material portion of the leases. Our oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties.

Facilities

 

Our executive and operating offices are located at Suite 650, Meridian Tower, 5100 E. Skelly Drive, Tulsa, Oklahoma 74135 which we occupy under a lease with a remaining term ending in January 2014, at an annual rental of approximately $0.4 million, subject to escalations for taxes and utilities. We also have an executive and operating office at 4965 Preston Park Blvd., Suite 800, in Plano, Texas, subject to a lease extending through 2013. Currently, rent under the lease is approximately $0.7 million annually. We have subleased a portion of our Plano office and will receive approximately $0.1 million annually. We also lease a small office in Houston, Texas. We believe that our facilities are adequate for our current needs.

 

Regulation

 

General.  Various aspects of our oil and gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and gas industry and our individual members.

 

Regulation of Sales and Transportation of Natural Gas.  The Federal Energy Regulatory Commission, or the FERC, regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which natural gas can be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation and proposed regulation designed to increase competition within the natural gas industry, to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers and to establish the rates interstate pipelines may charge for their services. Similarly, the Oklahoma Corporation Commission and the Texas Railroad Commission have been reviewing changes to their regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes being considered by these federal and state regulators would affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that any actions taken will have an effect materially different than the effect on other natural gas producers with which we compete.

 

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

 

Oil Price Controls and Transportation Rates.  Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market.

 

Environmental.  Our oil and natural gas operations are subject to pervasive federal, state, and local laws and regulations concerning the protection and preservation of the environment (e.g., ambient air, and surface and subsurface soils and waters), human health, worker safety, natural resources and wildlife. These laws and regulations affect virtually every aspect of our oil and natural gas operations, including our exploration for, and production, storage, treatment, and transportation of, hydrocarbons and the disposal of wastes generated in connection with those activities. These laws and regulations increase our costs of planning, designing, drilling, installing, operating, and abandoning oil and natural gas wells and appurtenant properties, such as gathering systems, pipelines, and storage, treatment and salt water disposal facilities.

 

In December 2009, the EPA promulgated a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas (“GHG”) regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, in

September 2009 and December 2010, the EPA also promulgated a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. These regulations may apply to our operations. The EPA has promulgated two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and which will likely affect sources in the oil and gas exploration and production industry and pipeline industry.

 

The GHG reporting rule and the stationary source GHG permitting rules to regulate the emissions of GHGs constitute federal regulation of carbon dioxide emissions and other GHGs, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry. See “Risk factors — Risks relating to our business — Regulation related to greenhouse gas emissions could have an adverse effect on our operations and demand for oil and natural gas.”

 

We have expended and will continue to expend significant financial and managerial resources to comply with applicable environmental laws and regulations, including permitting requirements. Our failure to comply with these laws and regulations can subject us to substantial civil and criminal penalties, claims for injury to persons and damage to properties and natural resources, and clean-up and other remedial obligations. Although we believe that the operation of our properties generally complies with applicable environmental laws and regulations, the risks of incurring substantial costs and liabilities are inherent in the operation of oil and natural gas wells and appurtenant properties. We could also be subject to liabilities related to the past operations conducted by others at properties now owned by us, without regard to any wrongful or negligent conduct by us.

 

We cannot predict what effect future environmental legislation and regulation will have upon our oil and natural gas operations. The possible legislative reclassification of certain wastes generated in connection with oil and natural gas operations as “hazardous wastes” would have a significant impact on our operating costs, as well as the oil and natural gas industry in general. The cost of compliance with more stringent environmental laws and regulations, or the more vigorous administration and enforcement of those laws and regulations, could result in material expenditures by us to remove, acquire, modify, and install equipment, store and dispose of wastes, remediate facilities, employ additional personnel, and implement systems to ensure compliance with those laws and regulations. These accumulative expenditures could have a material adverse effect upon our profitability and future capital expenditures.

 

Regulation of Oil and Gas Exploration and Production.  Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.

 

Employees

 

At December 31, 2010, we had 206 employees, of whom 42 were administrative, accounting or financial personnel and of whom 164 were technical and operations personnel. Our exploration staff includes three exploration geologists and six landmen. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreement and we have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

 

Available Information

 

Copies of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge through our website (www.ramenergy.com) as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC. Our SEC filings are

also available from the SEC’s website at: http://www.sec.gov. The references to our website address do not constitute incorporation by reference of the information contained on the website and should not be considered part of this report.

 

 

From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings, nor are we a party to any pending or threatened claims, that could reasonably be expected to have a material adverse effect on our financial condition or results of operations.

 

 

 

Market for Common Stock

 

Our common stock is traded on the Nasdaq Capital Market under the symbol RAME. The following table sets forth the range of high and low closing bid prices for our common stock for the periods indicated.

 

 

Holders

 

As of March 7, 2011, there were 98 holders of record of our common stock. We believe that at March 7, 2011, there were 5,921 beneficial holders of our common stock.

 

Dividends

 

It is the present intention of our board of directors to retain all earnings, if any, for use in our business operations and, accordingly, our board does not anticipate declaring any dividends in the foreseeable future. In addition, our credit facilities do not permit us to pay dividends on our common stock.

Compensation Plan Information

 

The following table provides information for all equity compensation plans as of the fiscal year ended December 31, 2010, under which our equity securities were authorized for issuance:

 

 

 

Stockholder Return Performance Presentation

 

The following graph and table compare the cumulative 5-year total return provided to our stockholders on our common stock beginning December 31, 2005, through December 31, 2010, relative to the cumulative total returns of the Nasdaq Composite index and the Dow Jones Wilshire MicroCap Exploration & Production index. The comparison assumes an investment of $100 (with reinvestment of all dividends) was made in our common stock on December 31, 2005, and in each of the indexes and its relative performance is tracked through December 31, 2010. The identity of the 50+ companies included in the Dow Jones Wilshire MicroCap Exploration & Production Index will be provided upon request.

 

COMPARISON OF 5 YEAR CUMULATIVE TOTL RETURN*
Among RAM Energy Resources, Inc., the NASDAQ Composite Index
and a Peer Group

 

 

 

We acquired RAM Energy, Inc. effective May 8, 2006, by the merger of our wholly owned subsidiary with and into RAM Energy. For accounting and financial reporting purposes, the merger was accounted for as a reverse acquisition and, in substance, as a capital transaction, because we had no active business operations prior to consummation of the merger. Accordingly, for accounting and financial reporting purposes, the RAM Energy acquisition was treated as the equivalent of RAM Energy issuing stock for our net monetary assets accompanied by a recapitalization. Our net monetary assets have been stated at their fair value, essentially equivalent to historical costs, with no goodwill or other intangible assets recorded. The accumulated deficit of RAM Energy has been carried forward. Operations prior to the merger are those of RAM Energy.

 

We acquired Ascent Energy Inc. on November 29, 2007, by the merger of our wholly owned subsidiary with and into Ascent. The Ascent acquisition was accounted for under the purchase method of accounting. Upon completion of the Ascent acquisition, Ascent adopted the full cost method of accounting for exploration, development and production of oil and natural gas.

 

The selected consolidated financial information presented below should be read in conjunction with our consolidated financial statements and the related notes, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained elsewhere in this report. Our financial position and results of operations for 2010, 2009, 2008 and 2007 may not be comparative to other periods as a result of certain divestitures and acquisitions, as more fully described in our consolidated financial statements included elsewhere in this report.

 

Selected Financial Data
(In thousands, except share data)

 

 

 

Selected Financial Data (continued)
(In thousands, except share data)

 

 

 

 

 

Our Modified EBITDA is determined by adding the following to net income (loss): interest expense, amortization and depreciation, accretion, income taxes, share-based compensation, impairment charges, settlement charges and unrealized gains (losses) on derivatives. The table below reconciles Modified EBITDA to net income (loss).

 

We present Modified EBITDA because we believe that it provides useful information regarding our continuing operating results. We rely on Modified EBITDA as a measure to review and assess our operating performance with corresponding periods, and as an assessment of our overall liquidity and our ability to meet our debt service obligations.

 

We believe that Modified EBITDA is useful to investors to provide disclosure of our operating results on the same basis as that used by our management. We also believe that this measure can assist investors in comparing our performance to that of other companies on a consistent basis without regard to certain items that do not directly affect our ongoing operating performance or cash flows. Modified EBITDA, which is not a financial measure under generally accepted accounting principles, or GAAP, has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for net income, cash flows from operating activities and other consolidated income or cash flows statement data prepared in accordance with GAAP.

Because of these limitations, Modified EBITDA should neither be considered as a measure of discretionary cash available to us to invest in the growth of our business, nor as a replacement for net income. We compensate for these limitations by relying primarily on our GAAP results and using Modified EBITDA as supplemental information.

 

 

 

General

 

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation, exploration and production of oil and natural gas properties, primarily in Texas, Louisiana and Oklahoma. Through our RAM Energy subsidiary, we have been active in our core producing areas of Texas, Louisiana and Oklahoma since 1987. Our management team has extensive technical and operating expertise in all areas of our geographic focus.

 

On December 8, 2010, we completed the sale to Milagro Producing, LLC, a privately owned company located in Houston, Texas, of all of our oil and natural gas properties and related assets located in the Boonsville and Newark East fields of Jack and Wise Counties, Texas. The effective date of the sale was October 1, 2010. The sale properties included all of our Bend Conglomerate shallow gas properties and all of our North Texas Barnett Shale properties, including both producing properties and undeveloped leasehold. We received net cash proceeds at closing of $42.3 million subject to customary post-closing adjustments. As of December 31, 2010, net proceeds including post-closing adjustments were $41.0 million. Proved reserves from these properties accounted for approximately 26.4 billion cubic feet equivalent (Bcfe) of natural gas, natural gas liquids and oil, or an estimated 13% of our year-end 2009 proved reserves of 204 Bcfe. Information as to our recent divestitures is set forth under Note B to the Consolidated Financial Statements.

 

Oil and natural gas prices have historically been volatile. In 2010, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $76.95 per Bbl and $4.21 per Mcf, respectively, a significant improvement over 2009 average realized prices of $58.24 per Bbl and $3.47 per Mcf, respectively. A significant decline in annual average prices for oil and natural gas began during the last half of 2008. Spot natural gas prices declined to $5.71 per Mcf on December 31, 2008, from $12.27 per Mcf on June 30, 2008, a decrease of approximately 53%. Oil prices in the last six months of 2008 experienced a 68% decrease, declining to $44.60 per Bbl on December 31, 2008, from $138.32 per Bbl on June 30, 2008. Natural gas and oil prices continued to decline into the first quarter of 2009. Prices improved in the fourth quarter of 2009 for oil, increasing 28% to $73.36 per Bbl compared to $57.56 in the 2008 period. Natural gas prices continued to decline to $3.93 per Mcf in the fourth quarter of 2009 from $5.05 in the fourth quarter of

2008, a 22% drop. It is impossible to predict the frequency, duration or outcome of any volatile price movements or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations and liquidity. We continue to monitor operations and planned capital budget expenditures as the economics of many projects may diminish as a result of prolonged natural gas price declines.

 

Critical Accounting Policies

 

The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect our reported assets, liabilities and contingencies as of the date of the financial statements and our reported revenues and expenses during the related reporting period. Our actual results could differ from those estimates. See Note A to our Consolidated Financial Statements included in Item 8 of this report for further discussions of our significant accounting policies and recently adopted accounting standards.

 

We follow the full cost method of accounting for oil and natural gas operations. Under this method all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves. The costs of unevaluated oil and natural gas properties are excluded from the amortizable base until the time that either proven reserves are found or it has been determined that such properties are impaired. As properties become evaluated, the related costs transfer to proved oil and natural gas properties using full cost accounting.

 

Under the full cost method the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the “Ceiling Limitation”). In arriving at estimated future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the Ceiling Limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the Ceiling Limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. At December 31, 2008, the net book value of our oil and natural gas properties exceeded the Ceiling Limitation resulting in reduction in the carrying value of our oil and natural gas properties by $269.4 million, or $171.6 million net of tax, and at March 31, 2009, the net book value of our oil and natural gas properties exceeded the Ceiling Limitation resulting in reduction in the carrying value of our oil and natural gas properties by $47.6 million, or $30.3 million net of tax. We incurred no impairment charge in 2010.

 

Estimates of our crude oil and natural gas reserves are prepared by independent petroleum and geological engineers in accordance with guidelines established by the SEC. Proved reserves, estimated future net revenues and the present value of our reserves are estimated based upon a combination of historical data and estimates of future activity. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of proved crude oil and natural gas reserves may significantly affect the amount at which oil and natural gas properties are recorded and significantly affect our amortization and depreciation expense.

 

On December 31, 2008, the SEC issued Release No. 33-8995 amending its oil and natural gas reporting requirements for oil and natural gas producing companies. Companies were not permitted to comply at an earlier date. Among other things, Release No. 33-8995: