HOUSTON, Feb. 17, 2011 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the year and fourth quarter ended December 31, 2010.

RESERVES

The Company's proved oil and natural gas reserves as of December 31, 2010 increased by 10% to 464 billion cubic feet equivalent ("Bcfe") of natural gas versus the prior year period.  Proved reserves at year-end did not include 32.5 Bcfe of proved developed reserves associated with the Company's sale of non-core assets that closed on December 30, 2010.  Proved reserves would have grown by 18% without the divestiture.  Year-end proved reserves were 98% natural gas and 41% 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 $362.1 million, using SEC pricing of $4.38 per MMbtu for natural gas and $75.96 per barrel of oil.  

The Company had reserve additions in 2010 of 107.7 Bcfe (90.8 Bcfe developed and 16.9 Bcfe undeveloped) prior to positive engineering and price revisions, on net cash drilling and completion capital expenditures on 2010 wells of $216.3 million, for an organic finding and development cost of $2.01 per Mcfe.  Proved developed finding and development cost for 2010 wells was $2.38 per Mcfe.  The Company had positive revisions of 1.8 Bcfe, comprised of 1.5 Bcfe of price revisions and 0.3 Bcfe of engineering revisions.  The Company's successful Haynesville Shale drilling program was the primary driver of the growth in proved reserves in 2010.

The following table reflects the changes in the proved reserve and proved developed reserve estimates since year-end 2009:

PRODUCTION

Production for the quarter increased by 6% sequentially and 13% over the prior year period to 8.9 billion cubic feet equivalent, or an average of 97,100 Mcfe per day.  Production from the Haynesville Shale comprised 55% of total volumes produced in the quarter, and 51% for the year.  Oil production increased 60% sequentially in the quarter to approximately 575 barrels per day or approximately 4% of total production on an Mcfe basis.

On December 30, 2010 the Company closed on its previously disclosed sale of non-core assets.  Production associated with the asset sale averaged 11,700 Mcfe per day in the fourth quarter.  Production for the first quarter of 2011 is expected to average 96,000 – 102,000 Mcfe per day, after factoring in the divestiture.  First quarter oil production is expected to comprise approximately 5 – 7% of total volumes, up from approximately 4% during the fourth quarter of 2010, and 2% during the third quarter of 2010.

Due to a 45% increase in allocation of capital to the Company’s Eagle Ford Shale Trend acreage, which is designed to significantly increase cash flow in 2011, the Company is reducing its production guidance on an Mcfe basis for 2011.  Production volumes in 2011, after factoring in the recent divestiture, are now expected to grow by 10 – 20%.  Oil volumes are expected to grow in excess of 400% over 2010, comprise 12 – 17% of total volumes, and exit the year in excess of 3,000 barrels per day.  

NET INCOME

The Company announced a net loss applicable to common stock of $21.2 million for the fourth quarter, or ($0.59) per basic share, versus a net loss applicable to common stock of $191.1 million, or ($5.34) per basic share in the prior year period.  The Company announced a net loss applicable to common stock of $268.2 million for the year, or ($7.47) per basic share, versus a net loss applicable to common stock of $257.0 million, or ($7.17) per basic share for the prior year.  The primary reason for the loss in both years was non-cash impairment charges of $234.9 million and $208.9 million in 2010 and 2009, respectively.  

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration (“EBITDAX”), was $29.8 million for the fourth quarter, compared to $39.1 million in the prior year period.  EBITDAX for the year totaled $108.7 million, compared to $141.8 million during the prior year period.  EBITDAX was down from last year’s record level, in spite of higher production volumes, due to lower realized natural gas prices including derivative gains in 2010 compared to the prior year period (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities).  

Discretionary cash flow (“DCF”), defined as net cash provided by operating activities before changes in working capital, was $22.9 million in the fourth quarter, compared to $48.9 million in the prior year period.  Note that DCF for the fourth quarter of 2009 was positively impacted by approximately $15.0 million in adjustments related to tax refunds available to the Company as a result of carrying back to recoup the previous year’s cash tax payments to state and federal taxing authorities.   Discretionary cash flow for the year was $82.5 million, versus $140.0 million in the prior year period. DCF in the current year was negatively impacted by lower realized natural gas prices including realized gains on derivatives versus the prior year period.  Net cash provided by operating activities was $100.4 million for the year, compared to $115.6 million for the prior year period (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities).    

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $91.1 million, of which $86.3 million was spent on drilling and completion costs and $4.8 million on acreage and other expenditures.  For the full year 2010, total capital expenditures booked during the year totaled $265.0 million in cash expenses and $17.4 million in accrual for a total of $282.4 million.  In 2010, the Company had $246.2 million in drilling and completion costs, $33.6 million for leasehold acquisition, $0.6 million for facilities and infrastructure, and $2.0 million for other expenditures.

For the purposes of calculating finding and development cost for 2010 reserve adds, we calculated net cash for drilling and completion expenditures (non-GAAP) of $216.3 million (see accompanying table for a reconciliation of net cash drilling and completion capital expenditures (non-GAAP) as used in the calculation of organic finding and development costs and organic proved developed finding and development costs to net cash used in investing activities (GAAP)).  

For 2011, the Company has increased its budget by $10.0 million to $235.0 million, and increased its allocation to the Eagle Ford Shale oil play by $45.0 million to $145.0 million.  The remainder of the budgeted amount is allocated as follows: $28.0 million in the core of the Haynesville Shale in North Louisiana, $24.0 million in the Angelina River Trend drilling Haynesville Shale wells, $23.0 million in South Henderson field drilling Cotton Valley Taylor sand wells (which have an oil yield of 25 – 40 barrels per million cubic feet of gas), and $15.0 million allocated to leasehold, seismic and infrastructure expenses.  Of the Company’s 2011 budget, approximately 62% is allocated to the Eagle Ford Shale Trend, which will drive cash flow growth for 2011.  

REVENUES

Revenues for the quarter were $36.3 million versus $32.2 million in the prior year period.  Revenues, including realized gain on derivatives not designated as hedges of $8.9 million for the quarter, would have been $45.2 million.  Average realized price per unit for the quarter, prior to factoring in the Company’s hedges, was $4.04 per Mcfe, versus $4.11 per Mcfe in the prior year period.  When factoring in the Company’s hedges, average realized price per unit for the quarter was $5.04 per Mcfe, versus $6.90 per Mcfe in the prior year period.

Revenues for the year totaled $148.3 million, versus $110.4 million in the prior year period.  Revenues, including realized gain on derivatives not designated as hedges of $24.6 million for the year, would have been $172.9 million.  Average realized price per unit for the year, prior to factoring in the Company’s hedges, was $4.39 per Mcfe, versus $3.72 per Mcfe in the prior year period.  When factoring in the Company’s hedges, average realized price per unit was $5.12 per Mcfe, versus $7.01 per Mcfe in the prior year period.

OPERATING EXPENSES

Lease operating expense ("LOE") decreased by 16% to $6.5 million in the quarter, or $0.72 per Mcfe, versus $6.8 million, or $0.86 per Mcfe in the prior year period.  LOE for the quarter includes the higher cost properties that were sold on December 30, 2010.  For the year, LOE totaled $26.3 million, or $0.78 per Mcfe, versus $30.2 million, or $1.01 per Mcfe in 2009, with the decrease on an absolute and per unit basis due primarily to the increasing production contribution from our Haynesville Shale wells, which averaged $0.19 per Mcfe LOE in the quarter.  Looking forward in 2011, the Company expects further reductions in its per unit LOE to a range of $0.55 – $0.70 per Mcfe.    

Production and other taxes for the quarter were $1.6 million, or $0.18 per Mcfe, versus $0.5 million, or $0.06 in the prior year period.  For the year, production and other taxes totaled $3.6 million, or $0.11 per Mcfe, versus $4.3 million, or $0.14 per Mcfe.

Transportation expense was $2.2 million, or $0.25 per Mcfe in the quarter, versus $2.0 million, or $0.25 per Mcfe in the prior year period.  For the year, transportation expense was $9.9 million, or $0.29 per Mcfe, versus $9.5 million, or $0.32 per Mcfe in the prior year.

Depreciation, depletion and amortization ("DD&A") expense for the quarter totaled $21.3 million, or $2.38 per Mcfe, versus $48.1 million, or $6.07 per Mcfe in the prior year period.  DD&A expense for the year totaled $105.9  million, or $3.14 per Mcfe, versus $160.4 million, or $5.38 per Mcfe for the prior year.

Exploration expense was $2.5 million, or $0.28 per Mcfe for the quarter, versus $2.5 million, or $0.31 per Mcfe in the prior year period.  Exploration expense for the year was $10.2 million, or $0.30 per Mcfe, versus $9.3 million, or $0.31 per Mcfe in the prior year.  Approximately 60% of exploration expense for the quarter, and 59% for the year, were non-cash expenses associated with amortization of the Company's undeveloped leasehold.

General and Administrative (G&A) expense was $7.2 million, or $0.81 per Mcfe in the quarter, versus $7.3 million, or $0.93 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, employees and directors of $2.1 million, or $0.23 per Mcfe, versus $2.0 million, or $0.25 per Mcfe in the prior year period.  For the year, G&A expense totaled $30.9 million, or $0.92 per Mcfe, versus $27.9 million, or $0.94 per Mcfe in the prior year.  Non-cash, stock based compensation for the year was 27% of total G&A booked, or $7.6 million, which was $0.22 per Mcfe, versus $6.8 million, or $0.23 per Mcfe for the prior year.  

Loss on sale of assets was $2.8 million, or $0.32 per Mcfe for the quarter, which was associated with the Company's non-core asset sale.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $7.8 million for the quarter versus an operating loss of $220.5 million for the prior year period.  When adding in realized gain on derivatives not qualifying as hedges of $8.9 million and the non-recurring loss on sale of assets of $2.8 million, adjusted operating income is $3.9 million.  Operating income for the year was a loss of $280.4 million, due to a $234.9 million impairment charge taken in the third quarter of 2010.

INTEREST EXPENSE

Interest expense for the quarter was $9.7 million, or $1.09 per Mcfe, versus $9.0 million, or $1.14 per Mcfe in the prior year period.  Non-cash interest expense associated with the Company’s convertible notes comprised 51% of the total, or $5.0 million ($0.56 per Mcfe) for the quarter.  For the year, interest expense was $37.2 million, or $1.10 per Mcfe, versus $26.1 million, or $0.88 per Mcfe in the prior year.  Non-cash interest expense for the year was $19.3 million, or $0.57 per Mcfe, versus $12.2 million, or $0.41 per Mcfe in the prior year period.  

LIQUIDITY

The Company exited 2010 with approximately $22.0 million in cash, restricted cash and short term investments and no borrowings under its senior bank credit facility, under which the Company currently has a borrowing base of $225.0 million.  The Company expects to finance the vast majority of its 2011 capital expenditure budget with cash and increasing cash flow driven by growth in oil volumes.  

COMMODITY HEDGE POSITION

As of December 31, 2010, the Company has 40,000 MMbtu per day of natural gas hedged for calendar years 2011 and 2012, with a floor price of $6.00 per MMbtu and a blended average ceiling price of $7.09 per MMbtu.  The Company also has 800 barrels of oil per day hedged at $100.00 per barrel for 2011, with the option held by the counterparty to extend the contract for two successive years on December 31, 2011 and 2012.

OPERATIONAL UPDATE

During the fourth quarter, the Company conducted drilling operations on 18 gross (8 net) wells, of which 4 gross (3 net) were in the Eagle Ford and 12 gross (4 net) were in the Haynesville Shale of North Louisiana.  A total of 16 gross (9 net) wells were added to production during the quarter.  For the year, the Company conducted drilling operations on 56 gross (27 net) wells, with a 100% success rate.  As of December 31, 2010, the Company had 16 gross (6 net) wells waiting on completion.

Eagle Ford Shale, LaSalle and Frio Counties, Texas

The Company has completed its Burns Ranch 4H (67% WI) well, a 4,600 foot lateral with 15 frac stages, at a 24-hour initial production rate of 600 barrels oil equivalent (“Boe”) per day.  

The Company has also completed its Pan Am C-1H (79.2% WI) well, an approximate 4,000 foot lateral with 14 frac stages, at a 24-hour initial production rate of 250 Boe per day.  The Pan Am C-1H is 330 feet off of the Company’s northern acreage border.

The Company is in completion phase on the Burns Ranch 9H (79.2% WI) which has a 5,300 foot lateral, Burns Ranch 7H (estimated 79.2% WI), with a 6,000 foot lateral and Pedro Morales 7H (79.2% WI), with a 6,000 foot lateral.  The Company is currently drilling its Burns Ranch 5H and Burns Ranch 16H wells, with estimated 79.2% WI in both wells.  

The Company has two drilling rigs running full time, and expects to drill 22 – 26 wells (up from 19 wells previously budgeted) due to a reduction in drill time, with a current estimated spud-to-spud of 25 days.  The Company is targeting approximately 6,000 foot laterals, with the majority of wells expected to be drilled in the southern half of the Company’s 40,000 net acres, where results have been at or above the Company’s expectations.

Joaquin Field, Shelby County, Texas

The Company has completed its initial Bossier Shale well on its 1,000 acre block in the Joaquin field of the Shelby Trough, the R. Dean 2H (82% WI), at an initial 24-hour production rate of 8,600 Mcfe per day on a 20/64 inch restricted choke with 5,500 psi.  The R. Dean 1H (80% WI) well, a 4,600 foot lateral with 15 frac stages in the Haynesville Shale, produced at a 24-hour rate of 5,700 Mcfe per day on a 16/64 inch restricted choke.

Angelina River Trend, Nacogdoches and Angelina Counties, Texas  

The Company is currently fracing its second well in the field, the Nelson 1H (100% WI), and expects results during the first quarter, with plans to drill one additional well in the field in the third quarter of 2011.  The Nelson 1H is an approximate 5,300 foot lateral in the Haynesville Shale.

Core Haynesville Shale – Northwest Louisiana

The Company completed 8 gross (3 net) Haynesville Shale wells in North Louisiana during the fourth quarter, including the Cason 14 H-1 (60%WI), which had a 24-hour initial production rate of 14,900 Mcfe per day on an 18/64 inch restricted choke with 8,600 psi.

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 Pre tax present worth discounted at 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 and the last is an alternative measure for valuing the Company's proved reserves.  Management also believes that these non-GAAP financial measures provide useful information to investors because they are widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and gas exploration and production industry.  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 .

The Company has provided the alternative proved reserve estimates in this release assuming natural gas prices other than those in effect on December 31, 2010 solely for illustrative purposes to demonstrate hypothetically the effect that year end economic conditions have on the Company's proved reserve estimates. The natural gas price used in one of these alternative presentations was selected by management based upon a review of longer term forward trading prices on the NYMEX, but does not necessarily reflect management's views as to future prices.  The United States Securities and Exchange Commission ("SEC") has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under economic and operating conditions existing at the date of the report. Accordingly, the SEC guidelines may prohibit us from including these alternatively priced proved reserve estimates in filings with the SEC.

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, 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.

CONTACT: Robert Turnham, President, or Jan Schott, Chief Financial Officer, both of Goodrich Petroleum Corporation, +1-713-780-9494