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

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 million was 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.

The following table reflects the changes in the proved reserve estimates since year-end 2010:

NET INCOME

The Company announced a net loss applicable to common stock of $23.8 million for the quarter, or ($0.66) per basic share, versus a net loss applicable to common stock of $21.2 million, or ($0.59) per basic share in the prior year period.  The Company announced a net loss applicable to common stock of $37.8 million for 2011, or ($1.05) per basic share, versus a net loss applicable to common stock of $268.2 million, or ($7.47) per basic share for 2010.  

REVENUES

Revenues for the quarter were $51.4 million versus $36.3 million in the prior year period.  Revenues, including realized gain on derivatives not designated as hedges of $9.9 million for the quarter, would have been $61.3 million.  Average realized price per unit for the quarter, prior to factoring in the Company's hedges, was $5.18 per Mcfe, versus $4.04 per Mcfe in the prior year period.  When factoring in the Company's hedges, average realized price per unit was $6.17 per Mcfe, versus $5.04 in the prior year period.

Revenues for the year totaled $201.1 million, versus $148.3 million in the prior year period.  Revenues, including realized gain on derivatives not designated as hedges of $31.3 million for the year, would have been $232.4 million.  Average realized price per unit for the year, prior to factoring in the Company's hedges, was $5.01 per Mcfe, versus $4.39 per Mcfe in the prior year period.  When factoring in the Company's hedges, average realized price per unit was $5.79 per Mcfe, versus $5.12 per Mcfe in the prior year period.

OPERATING EXPENSES

Lease operating expense ("LOE") decreased by 8% to $5.9 million in the quarter, or $0.60 per Mcfe, versus $6.5 million, or $0.72 per Mcfe in the prior year period.  For the year, LOE totaled $21.5 million, or $0.54 per Mcfe, versus $26.3 million, or $0.78 per Mcfe in the prior year period.  For 2012, the Company expects LOE to average between $0.55 – 0.75 per Mcfe.    

Production and other taxes for the quarter were $1.3 million, or $0.13 per Mcfe, versus $1.6 million, or $0.18 in the prior year period.  For the year, production and other taxes totaled $5.5 million, or $0.14 per Mcfe, versus $3.6 million, or $0.11 per Mcfe in the prior year period.  For 2012, the Company expects production and other taxes to average between $0.25 – 0.35 per Mcfe.

Transportation expense was $5.5 million, or $0.55 per Mcfe in the quarter, versus $2.2 million, or $0.25 per Mcfe in the prior year period.  Transportation expense in the quarter included capital reimbursement of third-party midstream costs.  For the year, transportation expense was $13.0 million, or $0.32 per Mcfe, versus $9.9 million, or $0.29 per Mcfe in the prior year period.  For 2012, the Company expects transportation expense to average between $0.35 – 0.40 per Mcfe.

Depreciation, depletion and amortization ("DD&A") expense for the quarter totaled $38.6 million, or $3.87 per Mcfe, versus $21.3 million, or $2.38 per Mcfe in the prior year period.  DD&A expense for the year totaled $131.8 million, or $3.29 per Mcfe, versus $105.9 million, or $3.14 per Mcfe for the prior year period.  For the first half of 2012, the Company expects DD&A to average between $3.75 – 4.00 per Mcfe.

Exploration expense was $1.9 million, or $0.19 per Mcfe for the quarter, versus $2.5 million, or $0.28 per Mcfe in the prior year period.  Exploration expense for the year was $8.3 million, or $0.21 per Mcfe, versus $10.2 million, or $0.30 per Mcfe in the prior year.  Approximately 67% of exploration expense for the quarter, and 66% for the year, was non-cash associated with amortization of the Company's undeveloped leasehold.  For 2012, the Company expects exploration expense to average between $0.20 – 0.25 per Mcfe.

Impairment expense was $6.9 million, or $0.69 per Mcfe for the quarter; the company did not incur an impairment during the prior year period.  Impairment expense for the year was $8.1 million, or $0.20 per Mcfe, versus $234.9 million, or $6.97 per Mcfe during the prior year period.  Impairment expense during the quarter was mostly due to falling natural gas prices related to our non-core Beckville field in East Texas.

General and Administrative ("G&A") expense was $8.0 million, or $0.80 per Mcfe in the quarter, versus $7.2 million, or $0.81 per Mcfe in the prior year period.  For the quarter, the Company recorded non-cash general and administrative expenses related to stock based compensation for its officers and employees of $2.0 million, or $0.20 per Mcfe, versus $2.1 million, or $0.23 per Mcfe in the prior year period.  For the year, G&A expense totaled $29.8 million, or $0.74 per Mcfe, versus $30.9 million, or $0.92 per Mcfe in the prior year period.  Non-cash, stock based compensation for the year was 22% of total booked G&A, or $6.5 million, which was $0.16 per Mcfe, versus $7.6 million, or $0.22 per Mcfe for the prior year period.  For 2012, the Company expects total G&A to average between $0.80 – 0.85 per Mcfe, with non-cash G&A expected to average approximately 20% of total G&A expense.  

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $16.9 million for the quarter versus an operating loss of $7.8 million for the prior year period.  Operating income for the year was a loss of $17.1 million versus an operating loss of $280.4 million for the prior year period, which included a $234.9 million asset impairment.

INTEREST EXPENSE

Interest expense for the quarter was $12.5 million, or $1.26 per Mcfe, versus $9.7 million, or $1.09 per Mcfe in the prior year period.  Non-cash interest expense associated with the Company's long term debt comprised 21% of the total, or $2.7 million ($0.27 per Mcfe).  For the year, interest expense was $49.4 million, or $1.23 per Mcfe, versus $37.2 million, or $1.10 per Mcfe in the prior year.  Non-cash interest expense comprised 29% of the total, or $14.4 million ($0.36 per Mcfe).  For 2012, the Company expects to average between $1.25 – 1.50 per Mcfe of interest expense with the non-cash portion comprising approximately $0.35 – 0.40 per Mcfe of the total.

LIQUIDITY

The Company exited the year with $3.3 million in cash and $102.5 million drawn on its senior bank revolving credit facility, under which the Company currently has a borrowing base of $275 million.  The Company expects to finance the vast majority of its 2012 capital expenditure budget with cash on hand and increasing cash flow driven by growth in oil volumes.  This is predicated upon numerous assumptions which include oil and natural gas pricing, drilling activity and production additions.  

COMMODITY HEDGE POSITION

The Company has 60,000 MMBtu per day of natural gas hedged for 2012, with an average floor price of $5.78 per MMBtu and 2,500 barrels of oil per day hedged at an average strike price of $100.56 per barrel.  

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 20 gross (8 net) wells, of which 3 gross (2 net) were in the Eagle Ford and 15 gross (6 net) were in the Haynesville Shale.  A total of 9 gross (4.8 net) wells were added to production during the quarter.  For the year, the Company conducted drilling operations on 54 gross (28 net) wells, with a 100% success rate.  As of December 31, 2011, the Company had 12 gross (4.5 net) wells waiting on completion, with 10 gross (3.2 net) in the Haynesville Shale Trend and 2 gross (1.3 net) in the Eagle Ford Shale Trend.

Texas

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas

The Company completed one Eagle Ford Shale well during the quarter, the Burns Ranch 35H (67% WI), with a peak 24-hour initial production rate of 835 BOE per day (88.3% oil, 11.7% gas), and three Buda Lime wells in the quarter, the Carnes 8H (67% WI), Shiner B 1H (67% WI) and Shiner G 4H (67% WI), at an average peak 24-hour initial production rate of 1,244 BOE per day (60% gas, 40% oil).  

Mississippi

Tuscaloosa Marine Shale Trend

The Company has participated for a 4.5% non-operated working interest in the Anderson 17H-1 well in Amite County, Mississippi.  The well, which was drilled with an approximate 7,300 foot lateral, is in completion phase with initial production expected early in the second quarter.  For the remainder of 2012, the Company currently expects to participate in one to five additional non-operated wells for a small working interest and two to five operated wells with an approximate blended average working interest of 60%.  The first operated well is expected to commence in early May.  With continued success, the Company will accelerate development in the play at the appropriate time.  

Louisiana

Haynesville Shale Trend

The Company participated in three completions in the quarter of small non-operated interest wells, the McEachern 9H-1 (6% WI), Cason 24H-1 (3% WI) and Frazier-Federal 1H (5% WI), with an average peak 24-hour initial production rate of 14,438 Mcf per day.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, EBITDAX, discretionary cash flow, Drilling and Completion capital expenditures, and year-end pre tax present worth of proved reserves discounted at 10% "PV-10".  Management believes that the first two of these measures are good financial indicators of the Company's ability to internally generate operating funds, while the third is a useful measure of the Company's annual drilling expenditures.   Neither discretionary cash flow nor EBITDAX should be considered an alternative to net cash provided by operating activities, as defined by GAAP, nor should Drilling and Completion capital expenditures be considered an alternative to Costs incurred in oil and gas property acquisition, exploration, and development activities, as defined by GAAP. Management also believes that year-end PV-10 of proved reserves discounted at 10% is a helpful comparative indicator of proved reserves from company to company without regard to an individual company's tax position, as is taken into account in reducing PV-10 by the discounted amount of estimated future income tax expense, resulting in the GAAP-required standardized measure of discounted future net cash flows ("SMOG").  The company's discounted future income taxes are estimated to be $4.0 million at December 31, 2011 to arrive at a SMOG of $450 million.  Management believes that all of these non-GAAP financial measures provide useful information to investors because they are monitored and used by Company management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and gas exploration and production industry.  

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.  In particular, production from horizontal drilling in shale gas resource plays and tight gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

Certain statements in this news release regarding future expectations and plans for future activities may be regarded as "forward looking statements" within the meaning of the Securities Litigation Reform Act.  They are subject to various risks, such as financial market conditions, changes in commodities prices and costs of drilling and completion, operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company's Annual Report on Form 10-K and other filings with the Securities and Exchange Commission.  Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

Goodrich Petroleum is an independent oil and gas exploration and production company listed on the New York Stock Exchange.  The majority of its properties are in Louisiana and Texas.

SOURCE Goodrich Petroleum Corporation

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