Goodrich Petroleum Announces Year-End and Fourth Quarter Financial Results and Revised 2012 Guidance

Thursday, Feb 23, 2012

HOUSTON, Feb. 22, 2012 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the year and fourth quarter ended December 31, 2011 and updated capital expenditure and production guidance for 2012.  

CAPITAL EXPENDITURES

The Company is maintaining its 2012 capital expenditure budget of $250 – 275 million, but reallocating$20 million of capital expenditures from its gas-focused Haynesville Shale properties to its oil-focused activities in the Eagle Ford Shale.  The revised capital expenditure budget allocates 85% of total spending towards oil-focused activity.

The Company anticipates conducting drilling operations, including wells spud in the fourth quarter of 2011, on 53 – 57 gross (31 – 33 net) wells in 2012.  Due to current depressed natural gas prices, the Company plans to defer completions on approximately 15 gross (7 net) Haynesville Shale wells, the majority of which were drilled in the fourth quarter of 2011 or the first quarter of 2012.  

The updated budget allots $175 million in the Eagle Ford Shale to drill 32 gross (22 net) wells, $20 – 45 million in the Tuscaloosa Marine Shale to drill 4 – 8 gross (2 – 4 net) wells, $17.5 million in the core Haynesville Shale to finish drilling operations on 15 gross (5.5 net) wells, $20 million in the Angelina River Trend to drill 2 gross (2 net) wells and $17.5 million in leasehold and infrastructure expense.

Capital expenditures for the quarter were $47.0 million (versus a budgeted amount of $50 – 55 million), of which $44.8 million was spent on drilling and completion costs, $2.2 million on leasehold acquisition, facilities and other expenditures.  For the full year 2011, capital expenditures incurred totaled $328.0 million, of which $270.9 million was for drilling and completion costs on wells drilled in 2011, $23.1 millionwas for carry-over drilling and completion costs, and $34.0 million was for leasehold, infrastructure and other expenditures.

PRODUCTION

With the reallocation of $20 million of capital expenditures to the Eagle Ford Shale, the Company anticipates oil volumes to grow by 135 – 165% over 2011 volumes and to exceed 5,000 barrels per day by year-end.  With the reduction in gas-focused capital expenditures and additional deferment of completions in the Haynesville Shale, the Company now expects natural gas production for the year to decline by 15 – 20%, and overall production on a Mcfe basis to be flat to down five percent.

Production for the first quarter of 2012 is expected to average 97,000 – 104,000 thousand cubic feet equivalent (“Mcfe”) per day, comprised of 2,500 – 3,000 barrels of oil and 82,000 – 86,000 Mcf per day of natural gas.  To date, the Company has completed one Eagle Ford Shale well in the first quarter of 2012, with two additional wells set for completion in March.  The Company expects to complete and put on production approximately eight Eagle Ford Shale Trend wells in the second quarter, including several pad-drilled wells.  

Production for the quarter was 10.0 billion cubic feet equivalent (“Bcfe”), or an average of 108,200 Mcfe per day, versus 8.9 Bcfe, or an average of 97,100 Mcfe per day in the prior year period.  Oil production for the quarter totaled 225,000 barrels of oil, or an average of 2,450 barrels per day, versus 53,000 barrels of oil, or 580 barrels per day in the prior year period.  Natural gas production for the quarter totaled 8.6 Bcf, or an average of 93,500 Mcf per day.  The Company completed and turned to sales one Eagle Ford Shale well and three Buda Lime wells during the quarter.  Production for the year totaled 644,000 barrels of oil, a 329% increase over 2010, and 36.2 Bcf of natural gas, or an average of 109,700 Mcfe per day, which was an increase of 19% over the prior year period.    

CASH FLOW

With the growth in oil volumes, earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("EBITDAX") for 2012 is now expected to grow by 40 – 60% to$240 –270 million when factoring in the Company's hedges and assuming a flat pricing case of $3.25 per Mcf of natural gas and $95.00 per barrel of oil or current strip pricing.  Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital is expected to grow by 50 – 70% to $200 – 225 million under the same pricing scenarios.  EBITDAX and DCF are non-GAAP financial measures, please refer to "Other Information" section for additional disclosure and information.

EBITDAX increased by 43% to $42.7 million in the quarter, compared to $29.8 million in the prior year period.  EBITDAX for the year increased by 56% to $169.2 million versus $108.7 million in the prior year period (see accompanying table for a reconciliation of EBITDAX, a non-GAAP financial measure, to net loss).  

DCF increased by 52% to $34.8 million in the quarter, compared to $22.9 million in the prior year period.  DCF increased by 62% to $133.8 million for the year, versus $82.5 million in the prior year period.  Net cash provided by operating activities for the year increased by 36% to $136.3 million, compared to $100.4 million for the prior year period (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP financial measure, to net cash provided by operating activities).  

YEAR-END RESERVES

The Company's proved oil and natural gas reserves as of December 31, 2011 increased by 8% versus the prior year period to 501.0 Bcfe. Oil and liquids reserves grew by 288% to 6.3 million barrels versus 1.6 million barrels at year-end 2010.  Year-end proved reserves were 92.5% natural gas, 7.5% oil and liquids (up from 2% at year-end 2010) and 42% developed.  The present value, using a 10% discount rate of the future net cash flows before income taxes of the proved reserves ("PV-10"), was $454 million, using SEC pricing of $4.12 per MMBtu for natural gas and $92.71 per barrel of oil.  Year-end PV-10 of proved reserves is a non-GAAP financial measure, please refer to "Other Information" section for additional disclosure and information.

The Company had reserve additions in 2011 of 105.8 Bcfe, with negative price and engineering revisions of 28.6 Bcfe.  The Company had approximately $270.9 million of net cash drilling and completion capital expenditures (including drilling carries associated with leasehold acquisition) associated with 2011 wells, for an organic finding and development cost of $2.56 per Mcfe ($15.36 per barrel of oil equivalent ("BOE")).  When stripping out the Company's payment of a drilling carry in the Eagle Ford Shale for leasehold acquisition of $34.8 million, the adjusted net cash capital expenditures for 2011 wells were $236.1 million, for an adjusted organic finding and development cost of $2.23 per Mcfe ($13.39 per BOE).  Approximately 75% of the drilling and completion capital expenditures associated with 2011 wells were from oil-focused activities.

The Company had proved developed reserve additions in 2011 of 69.6 Bcfe (66% of total proved reserve additions).  Proved developed finding and development cost for 2011 wells, including the drilling carry for leasehold acquisition, was $3.89 per Mcfe ($23.35 per BOE).  When deducting the above referenced drilling carry, adjusted proved developed finding cost was $3.39 per Mcfe ($20.35 per BOE).

The Company's successful Eagle Ford Shale drilling program was the primary driver of the growth in proved oil and liquids reserves in 2011.

SOURCE Goodrich Petroleum Corporation

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