The following discussion and analysis is intended to assist you in understanding our financial position and results of operations for each year in the three-year period ended December 31, 2008. You should read the following discussion and analysis in conjunction with our selected financial data and our accompanying audited Consolidated Financial Statements and the related notes to those financial statements included elsewhere in this report.
The following discussion and analysis contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see "Cautionary Statement Regarding Forward-Looking Statements" on page (i). Overview and Strategy
We are a Midland, Texas-based independent oil and natural gas exploration and production company focused on the acquisition, development and exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of our current producing properties are in the Permian Basin of west Texas and New Mexico, the Fort Worth Basin of north Texas, and the onshore Gulf Coast area of south Texas.
Our primary objective is to increase stockholder value by increasing reserves, production, cash flow and earnings. We attempt to target our investments in properties expected to produce consistently over the longer term, as contrasted to investments in properties having high rates of production in early years followed by rapid production declines. We also attempt to reduce our financial risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for acquisitions, exploitation and development drilling opportunities. Obtaining positions in long-lived oil and natural gas reserves are given priority over properties that might provide more cash flow in the early years of production, but which have shorter reserve lives. We also attempt to further reduce risk by emphasizing acquisition possibilities over high risk exploration projects.
Rather than emphasizing high risk exploration activities, we focus on established geologic trends where we can utilize the engineering, operational, financial and technical expertise of our entire staff. Although we expect to continue participating in exploratory drilling activities from time to time, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are important criteria in the execution of our business plan. In summary, our current business plan:
• focuses on projects having less geologic risk;

• emphasizes acquisition, exploitation, development and enhancement activities;

• includes the utilization of horizontal and fracture stimulation technologies on certain types of reservoirs;

• focuses on acquiring producing properties; and

• expands the scope of operations by diversifying our exploratory and development efforts, both in and outside of our primary areas of operation.

In addition to directing our exploration and development activities towards lower-risk development opportunities, we continually seek ways to maintain our expenses at levels we believe to be compatible with the size of our overall operations, utilize advanced technologies, serve as operator in appropriate circumstances, and reduce operating costs.
The extent to which we are able to implement and follow through with our business plan is influenced by:
• the prices we receive for the oil and natural gas we produce;

• the results of reprocessing and reinterpreting our 3-D seismic data;

• the results of our drilling activities;

• the costs of obtaining high quality field services;

• our ability to find and consummate acquisition opportunities;

• our ability to negotiate and enter into "work to earn" arrangements, joint ventures or other similar arrangements on terms acceptable to us; and

• sources and availability of funds to conduct operations and complete acquisitions.

Significant changes in the prices we receive for our oil and natural gas, or the occurrence of unanticipated events beyond our control, such as the recent and dramatic downturn in the financial markets, can cause us to defer or deviate from our business plans, including the amounts we have budgeted for our activities. In this regard, please read "Item 1. Business - Developments in 2008 and 2009" and "- 2009 Capital Budget".
Operating Performance
Our operating performance is influenced by several factors, the most significant of which are the prices we receive for our oil and natural gas and the quantities of oil and natural gas that we are able to produce. The world price for oil has overall influence on the prices that we receive for our oil production. The prices received for different grades of oil are based upon the world price for oil, which is then adjusted based upon the particular grade. Typically, light oil is sold at a premium, while heavy grades of crude are discounted. Natural gas prices we receive are influenced by:
• seasonal demand;

• weather;

• hurricane conditions in the Gulf of Mexico;

• availability of pipeline transportation to end users;

• proximity of our wells to major transportation pipeline infrastructures; and

• to a lesser extent, world oil prices.

Additional factors influencing our overall operating performance include:
• production expense;

• overhead requirements;

• costs of capital; and

• effects of our derivative contracts.

Results of Operations
Our oil and natural gas reserves at the end of 2008 were approximately 33.2 MMBoe with a reserves to production ratio of approximately 11.6 to 1. Our reserve to production ratio was 16.6 to 1 in 2007. The drop in this ratio from 2007 to 2008 was primarily the result of the decline in commodity prices in 2008. As described on page 21 of this Annual Report on Form 10-K, the failure to replace oil and natural gas reserves may negatively affect our business. We monitor this risk by comparing the quantity of our oil and natural gas reserves at the end of each year to our production for that year. This comparison, which is made in the form of a reserves to production ratio, helps us measure our ability to offset produced volumes with new reserves that will be produced in the future. The reserves to production ratio is calculated by dividing the total proved reserves at the end of a year by the actual production for the same year. The annual change in this ratio provides us with an indication of our performance in replenishing annual production volumes. The reserves to production ratio is a statistical indicator that has limitations. The ratio is limited because it can vary widely based on the extent and timing of new discoveries and property acquisitions. In addition, the ratio does not take into account the cost or timing of future production of new reserves and commodity pricing. For that reason, the ratio does not, and is not intended to, provide a measurement of value. For the year ended December 31, 2007, our production was 54% natural gas and 46% oil, as compared to approximately 64% natural gas and 36% oil for the year ended December 31, 2008.
Our business activities are characterized by frequent, and sometimes significant, changes in our:
• reserve base;

• sources of production;

• product mix (gas versus oil volumes); and

• the prices we receive for our oil and natural gas production.

Year-to-year or other periodic comparisons of the results of our operations can be difficult and may not fully and accurately describe our condition.
The following table shows selected operating data and operating income comparisons for each of the three years ended December 31, 2008.

                                                                     Years Ended December 31,
                                                            2008                  2007              2006
                                                               (in thousands, except per unit data)
Production Volumes:
Oil (Bbls)                                                      1,027                1,051            1,137
Natural gas (Mcf)                                              10,944                7,422            6,539
BOE                                                             2,851                2,288            2,227
BOE per day                                                       7.8                  6.3              6.1
Sale Prices:
Oil (per Bbl)(1)                                        $       95.25         $      65.97        $   59.86
Natural gas (per Mcf)(1)                                $        7.74         $       6.29        $    6.19
BOE Price(1)                                            $       64.02         $      50.72        $   48.73
BOE Price(2)                                            $       64.02         $      50.72        $   43.56
Operating Revenues:
Oil                                                     $      97,799         $     69,315        $  68,076
Effect of oil hedges                                                -                    -          (11,512 )
Natural gas                                                    84,716               46,716           40,461

                                                              182,515              116,031           97,025

Operating Expenses:
Lease operating expense                                        28,454               22,200           16,819
Production taxes                                                9,135                5,545            5,577
Production tax refund                                          (1,958 )             (1,209 )              -
General and administrative                                     11,907               10,415            9,523
Depreciation, depletion and amortization                       44,691               30,115           24,687
Impairment of oil and natural gas properties                  300,532                    -                -

                                                              392,761               67,066           56,606

Operating income (loss)                                 $    (210,246 )       $     48,965        $  40,419

(1) Excludes hedge transactions.

(2) Includes hedge transactions.

Critical Accounting Policies and Practices The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses. Certain accounting policies that require significant management estimates and that are deemed critical to our results of operations or financial position are discussed below. Our management reviews our critical accounting policies with the Audit Committee of our Board of Directors.
Use of Critical Accounting Estimates in the Preparation of Consolidated Financial Statements. The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. We define a critical accounting estimate as one that is both important to our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain.

Significant estimates include volumes of oil and natural gas reserves, abandonment obligations, impairment of undeveloped properties, income taxes, bad debts, derivatives, contingencies and litigation.
Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have a number of inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
Full Cost and Impairment of Assets. We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized. Costs of non-producing properties, wells in process of being drilled and significant development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined.
At the end of each quarter, capitalized costs, less accumulated amortization and related deferred income taxes, are limited to an amount (the ceiling) equal to the sum of: (i) The after tax present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; (ii) the cost of properties not being amortized; and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the ceiling, the excess shall be charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off shall not be reinstated for any subsequent increase in the cost center ceiling. A ceiling test write-down is a non-cash charge to earnings. It reduces earnings and impacts stockholders' equity in the period of occurrence and may result in lower depreciation, depletion and amortization expense in future periods. At December 31, 2008, the net book value of our oil and natural gas properties, less related deferred income taxes, was above the calculated ceiling. As a result, we were required to record an impairment of our oil and natural gas properties under the full cost method of accounting in the amount of $300.5 million for the year ended December 31, 2008. See Note 5- " Oil and Natural Gas Properties".
The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices decline. If commodity prices decline further, it is possible that we could incur additional impairments in future periods.
Depletion. Provision for depletion of oil and natural gas properties under the full cost method is calculated using the unit of production method based upon estimates of proved oil and natural gas reserves with oil and natural gas production being converted to a common unit of measurement based upon relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. The cost of any impaired property is transferred to the balance of oil and natural gas properties subject to depletion. The amortizable base includes estimated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. Oil and natural gas properties included $137.2 million and $86.4 million at December 31, 2008 and 2007, respectively, of unevaluated properties not subject to depletion.

In arriving at rates under the unit of production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by our geologists and engineers and require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion expense. There have been no material changes in our methodology of calculating the depletion of oil and natural gas properties under the full cost method during the three years ended December 31, 2008.
Proved Reserve Estimates. The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our year-end reserve estimates are prepared by independent petroleum engineers.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future revisions significantly reduce previously estimated reserve quantities, it could result in a full cost ceiling write-down. In addition to the impact of the estimates of proved reserves in calculating the ceiling test, estimates of proved reserves are also a significant component of the calculations of depreciation, depletion and amortization.
While estimates of the quantities of proved reserves require substantial subjective judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. Accounting principles generally accepted in the United States require that prices and costs in effect as of the last day of the period are held constant indefinitely. Accordingly, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on the last day of a quarter, can be either substantially higher or lower than prices we actually receive in the long-term, which are a barometer for true fair value.
Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). This standard takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Our deferred tax calculation requires us to make certain estimates about our future operations. Changes in state, federal and foreign tax laws, as well as changes in our financial condition or the carrying value of existing assets and liabilities, could affect these estimates. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. Additionally, the amount and availability of our loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests. The utilization of such carryforwards could be limited or lost upon certain changes in ownership and the passage of time. Although we believe it is more likely than not that we will be able to utilize all our loss carryforwards available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future.
Asset Retirement Obligations. Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143") requires us to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset,

depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, changes in the estimated timing of the cash flows, acquisition or construction of assets, and settlement of obligations.
Stock Based Compensation. We account for stock based compensation in accordance with the Financial Accounting Standards Board (FASB) SFAS No. 123
(revised 2004), "Share-Based Payment," ("SFAS 123 (R)"). We adopted SFAS 123(R)
effective January 1, 2006, applying the modified prospective method, whereby compensation cost associated with the unvested portion of awards granted during the period of June 2001 to December 2002 were recognized over the remaining vesting period. Under this method, prior periods were not revised for comparative purposes.
Litigation and Other Contingency Reserves. We estimate our reserves related to litigation and other contingencies based on the facts and circumstances specific to the litigation and contingency and our past experience with similar claims. The actual outcome of litigation and contingencies could differ significantly from estimated amounts.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of some of our customers to make required payments. These estimated allowances are periodically reviewed, on a case by case basis, analyzing the customer's payment history and information regarding customer's creditworthiness known to us. In addition, we record a reserve based on the size and age of all receivable balances against which we do not have specific reserves. If the financial condition of our customers was to deteriorate, resulting in their inability to make payments, additional allowances may be required.
Derivatives. The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended by Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities on Amendment of FASB Statement No. 133"("SFAS 138") that requires all derivative instruments to be recorded on the balance sheet at their respective fair values. We adopted SFAS 133 on January 1, 2001. To measure fair value we adopted SFAS No. 157, "Fair Value Measurements" ("SFAS 157"), effective January 1, 2008 for all financial assets and liabilities. In determining the fair value of our derivative contracts, we evaluate our counterparty and third party service provider valuations and adjust for credit risk when appropriate. We classify our fair value measurements as Level 3 if we do not have sufficient corroborating market evidence for volatility to support classifying these assets and liabilities as Level 2. See Note 9- "Derivatives".
During the period from January 1, 2003 to June 30, 2004, new derivative contracts were designated as cash flow hedges. These contracts remained designated as cash flow hedges through their settlement. Accordingly, the effective portion of the unrealized gains or losses was recorded in other comprehensive loss until the settlement of the contract position occurred. At settlement of these contracts, the cash value paid was recorded in revenue along with oil and natural gas sales, or in interest expense along with the interest expense that we incurred under our credit facilities. As of December 31, 2006, we had no remaining contracts which were designated as hedges.
Although we have designated our derivative contracts differently in different periods, the purpose of all of our derivative contracts is to provide a measure of stability in our oil and natural gas receipts and interest rate payments and to manage exposure to commodity price and interest rate risk under existing sales contracts.

Years Ended December 31, 2008 and December 31, 2007 The following discussion compares our result for the year ended December 31, 2008 to the year ended December 31, 2007. Unless otherwise indicated, references to 2008 and 2007 within this section refer to the respective annual periods.
Our oil and natural gas revenues and production product mix are shown in the following table for 2008 and 2007.
Oil and Gas Revenues

                                            Revenues           Production
                                         2008      2007      2008      2007
                   Oil (Bbls)              54 %      60 %      36 %      46 %
                   Natural gas (M cf)      46 %      40 %      64 %      54 %

                   Total                  100 %     100 %     100 %     100 %

The following table shows our production volumes, product sale prices and operating revenues for the periods indicated.

                                                                                   %
                              Year Ended December 31,          Increase        Increase
                                2008             2007         (Decrease)      (Decrease)
                                        (in thousands, except per unit data)
   Production Volumes:
   Oil (Bbls)                      1,027           1,051              (24 )            (2 )%
. . .