HEDGING UPDATEThe Company recently added crude oil swaps for 2013 on 2,000 barrels of oil per day and currently has 3,500 barrels of oil per day, or approximately 70% of 2013 estimated volumes hedged at NYMEX West Texas Intermediate ("WTI") price of approximately $94.50 per barrel. Current oil price differential to WTI is approximately + $12.00 per barrel for the Company's Eagle Ford Shale production and +$18.00 per barrel in the TMS. The Company is currently unhedged on natural gas. 2013 ESTIMATED CASH FLOW Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") is expected to be $165 – $185 million for the year factoring in the Company's production forecasts, hedges and based on NYMEX pricing of $90.00 per barrel of oil (WTI) and $3.50 per Mcf of natural gas. Commodity price differentials were estimated at a $10.00 per barrel premium to WTI on oil and Henry Hub pricing less $0.24 per Mcf on natural gas. Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital is expected to be $125 – $140 million under the same production, hedging and commodity price assumptions. Adjusted EBITDAX and DCF are non-GAAP financial measures. Please see "Other Information" below. LIQUIDITY The Company exited 2012 with $95 million drawn on its senior credit facility with a current borrowing base of $210 million, providing approximately $115 million of liquidity at year-end. The Company expects its borrowing base will increase incrementally in 2013 due to continued oil volume production and reserve growth and assuming no change in the bank group's commodity price assumptions, with its first redetermination due in March. Based on estimated capital expenditures and cash flow for 2013, the Company expects to finance approximately 70% of its capital expenditure budget with cash flow from operations and the balance with borrowings under its senior credit facility. The Company may seek additional liquidity through the joint venture of its TMS acreage or other monetizations, and if completed, will consider acceleration of its Eagle Ford and/or TMS drilling program in the second half of the year. OPERATIONAL UPDATE Eagle Ford Shale Average drilling days per well deceased by 40 percent sequentially in the quarter to 11 days for an average 6,000 foot lateral. Gross well costs for 2013 are projected to average $7.0 – $7.5 million for an average 6,000 foot lateral, which incorporates the lower well costs due to the faster drilling and cycle times achieved in the second half of 2012, as well as the reduced pressure pumping agreements in place for 2013. The Company currently plans to spud its initial Pearsall Shale test well in the first quarter. Tuscaloosa Marine Shale ("TMS") The Company was unable to repair the parted casing connection in the Denkmann 33H-1 (75% WI) and is currently working on plans to sidetrack the well at a later date. The Company has drilled its Crosby 12H-1 (50% WI) and is scheduled to commence fracking operations in January. The Crosby 12H-1 is an approximate 7,000 foot lateral with 23 planned frac stages. The Company has participated in the drilling of two non-operated wells, the Ash 31H-1 (12% WI) and Ash 31H-2 (12% WI), which are also expected to be fracked during January. The Ash 31H-1 is a 6,500 foot lateral and the Ash 31H-2 is currently drilling with a planned 7,000 foot lateral. Current plans for 2013 include participating as a non-operator in 4 – 6 gross (1.0 – 1.25 net) wells and drilling 2 – 4 gross (1.0 – 2.75 net) operated wells, with the potential to accelerate in the second half of the year. Goodrich's Chief Executive Officer, Walter G. "Gil" Goodrich stated, "We are pleased to announce our board approved capital expenditure budget and preliminary plans for 2013. The budget and planning is tailored to achieve a number of key objectives, including: (a) the continuation of our transition to a more balanced production and reserve mix between crude oil and natural gas; (b), maintain ample liquidity; (c), continue a high level of activity in the Eagle Ford Shale trend; (d), initiate development of the Pearsall Shale; and (e) further develop and define the economic value of our position in the Tuscaloosa Marine Shale trend. Our preliminary plans will allow us to achieve robust growth in oil production volumes over 2012, which will equate to approximately two-thirds of our projected revenue in 2013. The crude oil hedges we recently added for 2013 provide us price protection on approximately seventy percent of estimated crude oil production. Despite being currently unhedged on natural gas volumes, the high percentage of 2013 revenue and cash flow expected to be generated from crude oil production, as well as our crude oil hedges, provides solid overall cash flow protection. Based on our current production and commodity price forecasts, we anticipate approximately seventy percent of our capital expenditure budget will be funded with cash flow from operations. This high level of cash flow to capex coverage should in turn allow us to maintain ample liquidity during 2013 as we execute a number of strategic corporate objectives.