Forward-Looking Statements

Certain statements in this report, including statements of our future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside our control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to:

• planned capital expenditures;

• future drilling activity;

• our financial condition;

• business strategy;

• the market prices of oil and gas;

• economic and competitive conditions;

• legislative and regulatory changes; and

• financial market conditions and availability of capital.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Although from time to time we make use of futures contracts, swaps, costless collars and fixed-price physical contracts to mitigate risk, fluctuations in oil and gas prices, or a prolonged continuation of low prices may adversely affect our financial position, results of operations and cash flows.

Overview

We are an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley trend of East Texas and Northwest Louisiana, including the recently discovered Haynesville Shale play in the same general area. We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined in the Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 131, Disclosures about Segments of an Enterprise and Related Information.

We seek to increase shareholder value by growing our oil and gas reserves, production revenues and operating cash flow. In our opinion, on a long term basis, growth in oil and gas reserves and production on a cost-effective basis are the most important indicators of performance success for an independent oil and gas company.

Management strives to increase our oil and gas reserves, production and cash flow through exploration and exploitation activities. We develop an annual capital expenditure budget which is reviewed and approved by our

board of directors on a quarterly basis and revised throughout the year as circumstances warrant. We take into consideration our projected operating cash flow and externally available sources of financing, such as bank debt, when establishing our capital expenditure budget.

We place primary emphasis on our internally generated operating cash flow in managing our business. For this purpose, operating cash flow is defined as cash flow from operating activities as reflected in our Statement of Cash Flows. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains and losses.

Our revenues and operating cash flow are dependent on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and gas. Such pricing factors are largely beyond our control, however, we employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.

Cotton Valley Trend

Our relatively low risk development drilling program in the Cotton Valley trend is primarily centered in and around Rusk, Panola, Angelina, Nacogdoches, Cherokee, Harrison, Smith and Upshur Counties, Texas and DeSoto and Caddo Parishes, Louisiana. We continue to build our acreage position in the Cotton Valley trend and hold 201,203 gross acres as of December 31, 2008. As of year end 2008, we drilled and completed a cumulative total of 414 Cotton Valley trend wells with a success rate in excess of 98%. Our net production volumes from our Cotton Valley trend wells aggregated approximately 65,598 Mcfe per day in 2008, or approximately 99% of our total oil and gas production for the year.

2008 Haynesville Shale Transactions

Chesapeake Haynesville Joint Development

On June 16, 2008, we entered into a joint development agreement with Chesapeake Energy Corporation, or Chesapeake, to develop our Haynesville Shale acreage in the Bethany Longstreet and Longwood fields of Caddo and DeSoto Parishes, Louisiana. Chesapeake purchased the deep rights, including the Haynesville Shale, to approximately 10,250 net acres of oil and natural gas leasehold comprised of a 20% working interest in approximately 25,000 net acres in the Bethany Longstreet field and a 50% working interest in approximately 10,500 net acres in the Longwood field for net proceeds of $172.0 million. Chesapeake also purchased 7,500 net acres of deep rights in the Bethany Longstreet field from a third party (see Note 11 "Related Party Transactions" to our consolidated financial statements), bringing the ownership interest in the deep rights in both fields after closing to 50% each for us and Chesapeake. Chesapeake is the operator of the joint Haynesville Shale development. As a result of this transaction, we hold approximately 25,000 gross (12,500 net) acres in the deep rights in the Bethany Longstreet field and approximately 10,500 gross (5,250 net) acres in the deep rights in the Longwood field, both of which are currently believed to be prospective for the Haynesville Shale. Through our joint development arrangement with Chesapeake, we will continue to operate existing production and operate any new wells drilled to the base of the Cotton Valley sand, and Chesapeake will operate any wells drilled below the base of the Cotton Valley sand, including the Haynesville Shale.

We retained the shallow rights to the base of the Cotton Valley sand and the existing production and reserves with respect to our 70% working interest in the Bethany Longstreet field and our 100% working interest in the Longwood field. We also retained our interest in both the shallow and Haynesville Shale rights on all of our East Texas assets. During the third quarter of 2008, Chesapeake began drilling the Holland 17H No.1 as the first horizontal well on the joint acreage in Bethany Longstreet field. In the Longwood field, Chesapeake re-entered the Lona Johnson No.1 drilling it to the deeper Haynesville Shale as a horizontal well and recovered

154 feet of core from the formation to evaluate. During the fourth quarter of 2008, completion operations began on both of these wells and two horizontal Haynesville Shale development wells were spud in Bethany Longstreet field together with two Haynesville Shale wells in Longwood field. In 2009, we and Chesapeake plan to use approximately three rigs most of the year to drill 22 gross joint wells.

Caddo Parish Acquisition

On May 28, 2008, we acquired additional interests in the Cotton Valley trend, increasing our net exposure in the Haynesville Shale. We acquired approximately 3,665 net acres in Longwood field of Caddo Parish, Louisiana, through the issuance of 908,098 shares of our common stock valued at approximately $33.9 million. The purchase included interests in 25 gross wells, with approximately
1.1 Mmcfe per day of net production, and 5.2 Bcfe of proved reserves (77% developed) associated with the shallower Hosston and Cotton Valley formations. As of December 31, 2008, we had drilled and participated in three Haynesville wells.

Caddo Pine Island Acquisition

On June 10, 2008, we entered into a definitive agreement with a private company for the right to acquire over time a 50% non-operated interest in 5,800 gross (2,900 net) acres in the Caddo Pine Island field, north of and adjacent to our Longwood field in Caddo Parish, Louisiana. Total consideration paid was approximately $3.3 million, which was comprised of acreage costs for the 50% interest in the leasehold and the cost of a carried interest on the initial well drilled on the acreage. As of December 31, 2008, four wells had been drilled vertically to the Haynesville Shale on this acreage. In the fourth quarter of 2008, we re-entered two of these wells to drill them horizontally in the Haynesville Shale formation. Completion of the first horizontal well will start in the first quarter of 2009 and we expect to complete the other wells in the second quarter of 2009. In 2009, we plan to drill two additional horizontal Haynesville Shale wells on the acreage.

In connection with the Chesapeake joint development agreement, the Caddo Parish Acquisition and the Caddo Pine Island Acquisition, we have a total of approximately 22,000 net acres in North Louisiana which we believe to be prospective for the Haynesville Shale formation.

Initial Company Operated Haynesville Shale Drilling Program

As of December 31, 2008, we have been the operator on and drilled four vertical wells on our North Louisiana acreage and seven wells on our East Texas acreage, for a total of eleven vertical wells targeting the Haynesville Shale. In the fourth quarter of 2008, we began drilling our first operated horizontal Haynesville Shale well. We expect to complete this well in the first quarter of 2009. We expect that our development of the Haynesville Shale will continue in 2009 with the drilling and completion of nine company operated horizontal wells in East Texas.

Sale of South Louisiana Assets

On March 20, 2007, we completed the sale of substantially all of our assets in South Louisiana to a private company. The sale resulted in total proceeds of $72.3 million, net to us, after normal closing adjustments. We recognized a gain of $9.7 million (net of tax) in 2007. The effective date of the sale was July 1, 2006.

On August 4, 2008, we closed the sale of the St. Gabriel field to a private party for $0.1 million, resulting in a gain of $0.1 million. On August 12, 2008, we assigned our rights in the Bayou Bouillon field to a private party for a nominal amount. We realized a loss of $0.3 million. We continue to hold our interests in the Plumb Bob field. We have an asset retirement obligation of $1.4 million on the balance sheet for properties in the Plumb Bob field.

Overview of 2008 Results

• We achieved annual production volume growth of 51% with production growing from 16.0 Bcfe in 2007 to 24.2 Bcfe in 2008.

• We entered into an agreement with Chesapeake to jointly develop a portion of our Haynesville Shale acreage in Northwest Louisiana. We sold a portion of our interest in the Haynesville Shale deep rights at the Bethany Longstreet and Longwood fields to Chesapeake for net proceeds of $172.0 million resulting in a gain of $145.1 million. Chesapeake serves as operator for these properties.

• We established our presence in the Haynesville Shale play in Northwest Louisiana and East Texas and increased our ownership to approximately 63,000 net acres at December 31, 2008.

• We drilled and completed 126 gross (75.4 net) wells in 2008, as compared to 104 gross (64.65 net) wells in 2007.

• We raised net proceeds of $191.3 million from our equity offering in July 2008 and paid down all of the outstanding borrowings under our senior credit facility. We ended the year with $147.5 million in cash and short term investments.

• Estimated proved reserves grew 12% to approximately 402.3 Bcfe (approximately 390.4 Bcf of natural gas and 1.9 MMBbls of oil and condensate), with a PV-10 of $169.8 million (before discounted future income taxes of $2.4 million) and a standardized measure of $167.4 million, approximately 38% of which is developed.

• Capital expenditures totaled $380.1 million in 2008, versus $300.1 million in 2007.

• Our 2008 oil and gas revenues from continuing operations totaled $215.4 million compared to $110.7 million in 2007, a 95% increase.

• Net cash provided by operating activities increased $21.1 million from 2007, to $107.0 million in 2008.

• We reduced our total operating expenses by $0.90 per Mcfe from 2007 to 2008 excluding impairment expense and the impact of the $145.9 million gain on sale of assets during the third quarter of 2008 in making these calculations.

Summary Operating Information:                     Year End December 31,                                  Year End December 31,
    Continuing Operations                2008         2007              Variance              2007           2006              Variance
                                                                       (In thousands, except for price data)
Revenues:
Natural gas                            $ 199,057    $ 102,215      $  96,842       95 %     $ 102,215      $  67,372      $  34,843        52 %
Oil and condensate                        16,312        8,476          7,836       92 %         8,476          6,561          1,915        29 %
Natural gas, oil and condensate          215,369      110,691        104,678       95 %       110,691         73,933         36,758        50 %
Operating revenues                       216,051      111,305        104,746       94 %       111,305         74,771         36,534        49 %
Operating expenses                        70,624      146,464        (75,840 )    (52 %)      146,464         90,023         56,441        63 %
Operating income (loss)                  145,427      (35,159 )      180,586      514 %       (35,159 )      (15,252 )      (19,907 )    (131 %)
Net income (loss) applicable to
common stock                             130,191      (51,080 )      181,271      355 %       (51,080 )       (5,922 )      (45,158 )    (763 %)

Net Production:
Natural gas (MMcf)                        23,174       15,281          7,893       52 %        15,281         10,500          4,781        46 %
Oil and condensate (MBbls)                   167          118             49       42 %           118            106             12        11 %
Total (MMcfe)                             24,176       15,991          8,185       51 %        15,991         11,135          4,856        44 %
Average daily production (Mcfe/d)         66,054       43,811         22,243       51 %        43,811         30,507         13,304        44 %

Average Realized Sales Price Per
Unit:
Natural gas (per Mcf)                  $    8.59    $    6.69      $    1.90       28 %     $    6.69      $    6.42      $    0.27         4 %
Oil and condensate (per Bbl)               97.70        71.83          25.87       36 %         71.83          62.03           9.80        16 %
Average realized price (per Mcfe)           8.91         6.92           1.99       29 %          6.92           6.64           0.28         4 %

Results of Operations

For the year ended December 31, 2008, we reported net income applicable to common stock of $130.2 million, or $3.85 per share (basic) and $3.48 per share (diluted), on oil and gas revenues from continuing operations of $215.4 million. This compares to a net loss applicable to common stock of $51.1 million, or $2.00 per share (basic and diluted) for the year ended December 31, 2007, and a net loss applicable to common stock of $5.9 million, or $0.24 per share (basic and diluted) for the year ended December 31, 2006.

Some highlights for the year ended December 31, 2008 include:

• We recorded a $145.9 million gain on the sale of assets in a sale that closed in July 2008. This gain includes $145.1 million from the sale of a portion of our interest in the Haynesville Shale deep rights to Chesapeake.

• In conjunction with the decline in natural gas prices during late 2008, we recorded a $51.5 million gain on derivatives not designated as hedges for the year ended December 31, 2008. This includes a realized loss of $1.8 million and an unrealized gain of $55.4 million for our natural gas commodity contracts and a realized loss of $0.7 million and an unrealized loss of $1.4 million on our interest rate swaps.

• Our income tax expense for the year was reduced by a $25.5 million decrease in our valuation allowance related to our deferred tax assets. We released a majority of our valuation allowance in the third quarter of 2008 upon closing and recognizing a significant gain on the Chesapeake sale.

Operating Income

Year ended December 31, 2008 compared to year ended December 31, 2007

Revenues from continuing operations increased 94% compared to 2007, to a total of $216.1 million in 2008 due to a 51% increase in production and a 29% increase in the average realized price. Production increased year-to-year from 15,991 MMcfe to 24,176 MMcfe and our average realized price increased from $6.92 per Mcfe to $8.91 per Mcfe. The drilling and completion of 126 wells in the Cotton Valley trend resulted in the continued natural gas production growth for the company, even though we estimate we curtailed approximately 300 MMcfe of natural gas production in September 2008 as a result of Hurricane Ike. Operating expenses of $70.6 million for the year ended December 31, 2008, include the $145.9 million gain on sale of assets as a reduction in operating expenses and impairment expense of $28.6 million. Excluding the gain on sales of assets for 2008 and impairment expense for both 2008 and 2007, operating expenses of $187.9 million increased 35% or $49.1 million over 2007 operating expenses of $138.8 million (not including $7.7 million of impairment expense). This increase is a direct result of increased production from year-to-year. Although revenues were up significantly for the full year, we experienced a substantial reduction in revenues in the last half of 2008 versus the first half of the year, due to the substantial oil and natural gas price declines.

Year ended December 31, 2007 compared to year ended December 31, 2006

Operating revenues increased 49%, or $36.5 million, compared to 2006, to a total of $111.3 million in 2007 due to production increases and a slight increase in average realized price per Mcfe. Production increased 44% year-to-year from 11,135 MMcfe to 15,991 MMcfe and our average realized price increased 4% from $6.64 Mcfe to $6.92 per Mcfe. The drilling and completion of 95 wells in the Cotton Valley trend led to the gains in natural gas production for 2007. Operating expenses increased 63% to $146.5 million in 2007. The primary driver behind the $56.4 million increase in operating expenses was a $42.5 million increase in depreciation, depletion and amortization ("DD&A") year-to-year.

Year Ended December 31, Year Ended December 31, Operating Expenses per Mcfe 2008 2007 Variance 2007 2006 Variance Lease operating expenses $ 1.32 $ 1.40 $ (0.08 ) (6 %) $ 1.40 $ 1.14 $ 0.26 23 % Production and other taxes 0.31 0.14 0.17 121 % 0.14 0.30 (0.16 ) (53 %) Transportation 0.36 0.37 (0.01 ) (3 %) 0.37 0.34 0.03 9 % Depreciation, depletion and
amortization 4.43 4.99 (0.56 ) (11 %) 4.99 3.34 1.65 49 % Exploration 0.35 0.46 (0.11 ) (24 %) 0.46 0.53 (0.07 ) (13 %) Impairment of oil and gas
properties 1.18 0.48 0.70 146 % 0.48 0.89 (0.41 ) (46 %) General and administrative 1.00 1.31 (0.31 ) (24 %) 1.31 1.55 (0.24 ) (15 %)

Operating Expenses

Year ended December 31, 2008 compared to year ended December 31, 2007

LOE decreased $0.08 per Mcfe, or 6%, on a per unit basis compared to 2007. Production gains of 51% year-over-year offset the impact of generally higher costs. On an absolute dollar basis, LOE increased $9.5 million or 42% for 2008 as compared to 2007. The largest cost components of LOE for 2008 include salt water disposal ("SWD") costs of $9.7 million, compressor rental costs of $6.6 million and LOE for properties operated by others ("Non-Op") of $2.0 million. SWD and compressor rental costs tend to fluctuate with production. As a result of increased production, SWD increased $3.0 million in 2008 ($9.7 million or $0.40 per Mcfe for 2008 versus $6.7 million or $0.42 per Mcfe for 2007). Compressor rental costs increased $2.1 million in 2008 ($6.6 million or $0.27 per Mcfe for 2008 versus $4.5 million or $0.28 per Mcfe for 2007). Both of these cost areas were relatively flat on a per Mcfe basis. Non-Op LOE also increased $1.1 million ($2.0 million or $0.08 per Mcfe for 2008 versus $0.9 million or $0.06 per Mcfe for 2007) due to a greater number of our properties being operated by others. The remaining $3.3 million increase year-to-year represents the increased cost of labor, services and chemicals partially offset by lower workover costs. Workover costs represented $0.16 per Mcfe of the LOE rate for 2007, while workover costs only represented $0.06 per Mcfe of the LOE rate for 2008, due to fewer workover projects slated for 2008.

Production and other taxes of $7.5 million for 2008 include production tax of $5.5 million and ad valorem tax of $2.0 million. For 2007, production and other taxes of $2.3 million include production tax of $1.1 million and ad valorem tax of $1.2 million. Production tax for 2008 is net of $3.2 million of accrued Tight Gas Sands ("TGS") credits for our wells in the State of Texas, which credits equate to $0.13 per Mcfe of production. This compares to TGS credits of $3.9 million for 2007. These TGS credits allow for reduced and in many cases the complete elimination of severance taxes in the State of Texas for qualifying wells for up to ten years of production. We only accrue for such credits once we have been notified of the State's approval. We also anticipate lower production tax rates in the future as we continue to add Cotton Valley trend wells to our production base and as credits are approved. Production taxes are higher for 2008 as the result of a 51% increase in production over 2007, as well as the higher prices received during the year.

Ad valorem taxes increased to $2.0 million for 2008 from $1.2 million for 2007. Ad valorem tax is assessed on the value of properties as of the first day of the year and is highly influenced by commodity prices for the prior several months. The number of properties we owned increased from January 1, 2007 to January 1, 2008 and the assessed values for our existing properties were higher year-to-year. The combination of these two factors led to the increase in ad valorem taxes year-to-year.

Transportation expense increased 45% to $8.6 million in 2008 compared to $6.0 million in 2007, as a result of a 51% increase in production year-to-year. The rate per Mcfe decreased slightly to $0.36 per Mcfe in 2008 from $0.37 the prior year.

DD&A expense increased to $107.1 million in 2008 from $79.8 million in 2007 due to a 51% increase in production year-to-year. The DD&A rate declined from $4.99 per Mcfe for 2007 to $4.43 per Mcfe for 2008. We calculated the first and second quarter 2008 DD&A rates using the December 31, 2007 reserves. During the third quarter of 2008, we engaged an independent engineering firm to fully engineer our June 30, 2008 proved reserve estimates. The mid-year reserve report was used to calculate the rate for the third and fourth quarters of 2008. The DD&A rate per Mcfe based on this report resulted in a DD&A rate of $4.17 per Mcfe and $4.11 per Mcfe for the third and fourth quarters of 2008, respectively. These rates are lower than the rates used for the first half of 2008 due to the cost effective drilling of wells in the first six months of 2008. We engaged the same firm to prepare a mid-year reserve report in 2007 as well as year-end reports since 2005.

Exploration expense for 2008 increased to $8.4 million from $7.3 million for 2007. The primary component of exploration expense for us is the amortization of undeveloped leasehold costs, which represented $5.8 million of the total. Exploration expenses on a per unit basis declined by 24% from $0.46 per Mcfe for 2007 to $0.35 per Mcfe for 2008. Exploration expenses include $0.3 million for exploratory dry hole costs.

We recorded impairment expense of $28.6 million in 2008, $27.5 million in connection with our independent engineer's report on our reserves as of December 31, 2008. The expense relates to the Brachfield, Blocker, Alabama Bend and Gilmer Fields, which are located in non-core areas in North Louisiana and East Texas. We recorded an impairment expense of $7.7 million in 2007 for our Alabama Bend field and two wells in a non-core area of East Texas.

General and administrative ("G&A") expense increased 16% to $24.3 million for 2008 compared to $20.9 million for 2007. G&A on a per unit basis decreased 24% to $1.00 per Mcfe resulting from a 51% increase in production volumes in 2008 as compared to 2007. This increase in costs results from a 33% increase in the number of employees from 86 at December 31, 2007 to 114 at December 31, 2008. Stock based compensation expense, which is a non-cash item, amounted to $5.5 million in 2008 compared to $5.3 million for 2007.

Year ended December 31, 2007 compared to year ended December 31, 2006

LOE for 2007 increased 78% to $22.5 million from $12.7 million for 2006. Generally higher operating costs, primarily SWD and compression costs, contributed to the majority of the increase in 2007. Most of our fields . . .