HOUSTON, May 4, 2011 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced its financial and operating results for the first quarter ended March 31, 2011.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("EBITDAX"), increased by 41% to $33.7 million for the quarter, compared to $24.0 million in the prior year period (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities). EBITDAX was 13% higher sequentially.

DCF, defined as net cash provided by operating activities before changes in working capital, was $26.8 million for the quarter, compared to $10.2 million in the prior year period. DCF for the first quarter increased by 17% sequentially compared to the fourth quarter of 2010. Net cash provided by operating activities for the first quarter was $6.5 million.

See “Selected Cash Flow Data” at the end of this release for a reconciliation of EBITDAX and DCF to the comparable GAAP financial measure, net cash provided by operating activities.

NET INCOME

The Company announced a net loss applicable to common stock of $24.7 million for the quarter, or $0.68 per basic share, versus net income applicable to common stock of $2.8 million, or $0.08 per basic share in the prior year period.

PRODUCTION

Net production volumes in the quarter increased by 14% to 9.1 billion cubic feet equivalent ("Bcfe"), or an average of 100,800 Mcfe per day, versus 8.0 Bcfe, or an average of 88,600 Mcfe per day in the prior year period. Average net daily production volumes for the quarter were up 4% sequentially from the fourth quarter of 2010, despite the divestiture of 11,700 Mcfe per day of production in the fourth quarter of 2010.

Production for the second quarter of 2011 is expected to average 104,000 – 108,000 Mcfe per day, with oil production expected to comprise approximately 8 – 10% of total volumes, up from approximately 5.3% in the first quarter.

REVENUES

Revenues for the quarter were $41.2 million versus $40.5 million in the prior year period. Revenues, including realized gain on derivatives not designated as hedges of $7.1 million for the quarter, would have been $48.4 million. Average realized price per unit for the quarter, prior to factoring in the Company’s hedges, was $4.51 per Mcfe, versus $5.07 per Mcfe in the prior year period. When factoring in the Company’s hedges, average realized price was $5.30 per Mcfe, versus $5.27 per Mcfe in the prior year period.

OPERATING EXPENSES

Per unit operating expenses decreased by 38% from the prior year period and 5% sequentially, broken out as follows:

LOE on a per unit basis decreased by 41% to $4.9 million in the quarter, or $0.54 per Mcfe, versus $7.2 million, or $0.91 per Mcfe in the prior year period. Per unit LOE for the quarter decreased by 25% sequentially from the fourth quarter of 2010. Lower per unit LOE continued to be driven by the Company’s Haynesville Shale wells, which comprised 66% of Company volumes and averaged $0.18 per Mcfe for the quarter. The Company’s Eagle Ford Shale wells averaged $0.79 per Mcfe in the quarter. The Company continues to expect LOE per unit to be $0.55 – $0.70 per Mcfe in 2011.

Production and other taxes for the quarter decreased on a unit basis by 17% to $1.0 million, or $0.10 per Mcfe, versus $1.0 million, or $0.12 per Mcfe in the prior year period. Production and other taxes decreased by 44% sequentially on a per unit basis from the fourth quarter of 2010.

Transportation expense on a per unit basis decreased by 16% to $2.4 million, or $0.26 per Mcfe in the quarter, versus $2.5 million, or $0.31 per Mcfe in the prior year period. Transportation expense on a per unit basis increased by 4% sequentially from the fourth quarter of 2010.

DD&A expense on a per unit basis decreased by 27% to $25.0 million, or $2.75 per Mcfe in the quarter, versus $30.2 million, or $3.79 per Mcfe in the prior year period. DD&A expense for the quarter on a per unit basis increased by 16% sequentially due to the Company capturing production but not DD&A expense from its properties sold in the fourth quarter of 2010.

Exploration expense on a per unit basis decreased by 27% to $2.4 million, or $0.27 per Mcfe for the quarter, versus $3.0 million, or $0.37 per Mcfe, in the prior year period. Exploration expense for the quarter on a per unit basis decreased by 4% sequentially. Approximately $1.6 million ($0.18 per Mcfe), or 67% of exploration expense, for the quarter was non-cash associated with amortization of the Company’s undeveloped leasehold.

G&A expense on a per unit basis decreased by 23% to $8.3 million, or $0.91 per Mcfe in the quarter, versus $9.4 million, or $1.18 per Mcfe in the prior year period. Per unit G&A increased by 12% sequentially. Of the total G&A expense for the quarter, $1.8 million ($0.20 per Mcfe), or 22% of the total, was non-cash expense associated with stock based compensation, versus $2.5 million ($0.31 per Mcfe), or 27% of the total, in the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $2.4 million for the quarter versus an operating loss of $21.3 million for the prior year period. When adding in realized gain on derivatives not qualifying as hedges of $7.1 million, adjusted operating income for the quarter is $4.8 million.

OTHER INCOME (EXPENSE)

Interest expense for the quarter was $10.8 million, or $1.19 per Mcfe, versus $9.1 million, or $1.14 per Mcfe in the prior year period. Non-cash interest expense associated with the Company's convertible notes comprised 43% of the total, or $4.6 million ($0.51 per Mcfe).

Gain (loss) on derivatives not designated as hedges for the quarter was a loss of $10.0 million, or $1.10 per Mcfe, versus a gain of $34.7 million, or $4.35 per Mcfe in the prior year period. The derivative loss for the quarter is comprised of a realized gain of $7.1 million and an unrealized loss of $17.1 million.

LIQUIDITY

The Company ended the quarter with approximately $51.0 million in cash and equivalents, $33.3 million in restricted cash and no borrowings under its senior bank revolving credit facility, under which the Company currently has an available borrowing base of $225 million.

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $90.9 million, of which $88.1 million was spent on drilling and completion costs, $2.4 million on acreage acquisitions and $0.4 million on other expenditures. For the quarter, the Company conducted drilling operations on 21 gross (9 net) wells, of which 8 gross (6 net) were in the Eagle Ford, 10 gross (3 net) were in the Haynesville Shale, 1 gross (1 net) was in the Cotton Valley Taylor sand and 2 gross (1 net) were in other areas. A total of 16 gross (8 net) wells were added to production during the quarter, comprised of 3 gross (2 net) wells in the Eagle Ford, 12 gross (4 net) in the Haynesville Shale and 1 gross (1 net) wells in the Cotton Valley. The Company had 11 gross (4 net) wells waiting on completion at the end of the quarter.

OPERATIONAL UPDATE

Texas

Eagle Ford Shale, LaSalle and Frio Counties, Texas

The Company has completed its Burns Ranch 7H (67% WI) well, a 5,800 foot lateral with 21 frac stages, at a 24-hour initial production rate of 940 barrels oil equivalent (“BOE”) per day, comprised of 822 barrels of oil and 700 Mcf of natural gas per day.

The Company has completed its Burns Ranch 9H (79% WI) well (previously released in an 8K), a 5,240 foot lateral with 19 frac stages, at a 24-hour initial production rate of 860 BOE per day, comprised of 820 barrels of oil and 245 Mcf of natural gas per day.

The Company has completed its Burns Ranch 5H (67% WI) well, a 5,500 foot lateral with 20 frac stages, at a 24-hour initial production rate of 600 BOE per day, comprised of 570 barrels of oil and 200 Mcf of natural gas per day.

The Company has completed its Pedro Morales 7H (79% WI) well on the northern portion of its block in Frio County, Texas. The well, which had an approximate 6,570 foot lateral and 18 frac stages, produced at a 24-hour initial production rate of 460 BOE per day on hydraulic pump, comprised of 400 barrels of oil and 325 Mcf of natural gas per day.

The Company is in completion phase on the Burns Ranch 15H (67% WI) which has a 9,200 foot lateral, and the Burns Ranch 16H (67% WI), with a 5,700 foot lateral. The Company has commenced pad drilling on a portion of its block, with the Burns Ranch 19H (67% WI), Burns Ranch 20H (67% WI) and Burns Ranch 3H (67% WI) in drilling phase off of the same pad. In addition, the Company is currently drilling its Burns Ranch 17H (67% WI) well with a second rig.

The Company has two rigs running full time, with the majority of wells expected to be drilled in the southern half of the Company’s approximate 40,000 net acres, and expects to drill 22 – 26 wells in 2011.

Angelina River Trend, Nacogdoches and Angelina Counties, Texas

The Company has completed its Nelson 1H (100% WI), at a 24-hour production rate of 12,400 Mcf of natural gas per day with 11,500 psi on a restricted 14/64 inch choke. The well has been producing for approximately two months and is currently producing 10,400 Mcf of natural gas per day. The Nelson 1H has a 4,860 foot lateral with 15 frac stages. The Company plans to drill one additional well in the field in 2011.

Cotton Valley Taylor Sand, South Henderson Field, Rusk County, Texas

The Company has completed its second Taylor sand horizontal well in the field, the Craig 3H (100% WI), at a 24-hour production rate of 11,100 Mcfe per day, comprised of 8,950 Mcf of natural gas per day and 360 barrels of oil per day. The Craig 3H has a 4,670 foot lateral with 14 frac stages. The Company is currently drilling its Craig 4H (100% WI), with plans to drill the Travis Crow – Holland 1H (100% WI) immediately following.

OTHER INFORMATION

In this press release, the Company refers to two non-GAAP financial measures, EBITDAX and discretionary cash flow. Management believes that each of these measures is a good financial indicator of the Company's ability to internally generate operating funds. Management also believes that these non-GAAP financial measures of cash flow 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 natural 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.

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 and uncertainties, such as availability of drilling rigs and completion crews and equipment, 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.

Initial production rates stated in this release are expected to differ substantially from longer term average production rates. Forward looking estimates of production growth assume drilling results comparable to recent prior periods, which may not be realized. The Company is commencing its initial operations in the Eagle Ford Shale and the success of its drilling and completion strategy is subject to more uncertainty relative to areas where the Company has already established drilling and production history.

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

CONTACT: Robert Turnham, President, or Jan Schott, Chief Financial Officer, +1-713-780-9494