HOUSTON, May 6, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the first quarter ended March 31, 2013.

• Production for the quarter averaged 66.6 million cubic feet equivalent per day, comprised of an average of 3,423 barrels of oil and 46.0 million cubic feet per day. Oil and gas production for the quarter was negatively impacted by approximately 300 barrels of oil and 4,000 Mcf per day due to shut-in wells while fracing pad-drilled and/or offset wells in both the Eagle Ford and Haynesville Shale areas. Despite the shut-ins for the quarter, the Company reaffirms full year guidance of annual oil production volume growth of 40-60% and natural gas production volume growth of 10% from fourth quarter of 2012 to fourth quarter of 2013, as completions will accelerate at a faster pace than in the first quarter.
• Oil production comprised 31% of total production and 70% of revenues for the first quarter, with average realized oil price of $107.02 due to premium pricing agreements. Average realized price per Mcfe of production was $7.88 per Mcfe, including realized gain on hedges.
• Tuscaloosa Marine Shale development continuing, with four wells in completion phase and second operated well (Smith 5-29H-1) drilling. Improving drilling cycle times experienced on recent wells, are leading to improved drilling costs. The Goodrich Petroleum - Crosby 12H-1 well continuing to outperform the Company's 800,000 BOE type curve, with approximately 75,000 BOE (91% oil) produced in three months, with current production of approximately 700 BOE per day. The Company has participated with a non-operated working interest in the Ash 31H-2 well, which is a 5,300 foot lateral with 18 frac stages. The well has been flowing back for approximately two weeks and is still cleaning up due to the large frac job of one million pounds of proppant and 29,000 barrels of fluid per stage. Current 24-hour peak rate is approximately 730 BOE per day (92% oil), with 4% of the frac fluid recovered.
• Liquidity enhanced with increased borrowing base to $225 million and $110 million in gross proceeds from issuance of non-convertible perpetual preferred stock in April 2013. Proforma liquidity of approximately $190 million at quarter-end.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") was $27.1 million in the quarter, compared to $40.4 million in the prior year period and $50.5 million in the prior quarter.

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $16.3 million in the quarter, compared to $29.9 million in the prior year period and $39.9 million in the prior quarter. Net cash provided by operating activities was $6.3 million, compared to $30.5 million for the prior year period.

For the quarter both Adjusted EBITDAX and DCF were impacted by additional general and administrative expense of $1.5 million primarily for 2012 employee bonuses paid in 2013 and increased payroll taxes, approximately $1.6 million for workovers performed in the quarter, primarily in the Eagle Ford trend and $0.4 million for seismic expense.

(See accompanying tables at the end of this press release that reconcile Adjusted EBITDAX and DCF, each of which are non-GAAP financial measures, to their most directly comparable GAAP financial measure.)

NET INCOME

The Company announced a net loss applicable to common stock of $30.0 million for the quarter, or ($0.82) per basic share, versus a net loss applicable to common stock of $19.2 million, or ($0.53) per basic share in the prior year period. Adjusted net loss applicable to common stock, taking into effect the unrealized loss on derivatives not designated as hedges of $2.1 million and non-recurring exploration expense of $0.2 million, was $27.7 million.

(See accompanying tables at the end of this press release that reconcile adjusted net loss applicable to common stock, a non-GAAP measure, to its most directly comparable GAAP financial measure.)

PRODUCTION

Production for the quarter was 6.0 billion cubic feet equivalent ("Bcfe"), or an average of 66,600 Mcfe per day, versus 8.8 Bcfe, or an average of 96,300 Mcfe per day in the prior year period. Oil production for the quarter totaled 308,000 barrels of oil, or an average of 3,423 barrels per day, versus 217,000 barrels of oil, or 2,400 barrels per day, in the prior year period. Natural gas production for the quarter totaled 4.1 Bcf, or an average of 46,000 Mcf per day. Oil and gas production for the quarter was negatively impacted by approximately 300 barrels of oil and 4,000 Mcf per day due to completion delays and the necessity to shut in wells while fracing pad-drilled and/or offset wells in both the Eagle Ford and Haynesville Shale areas.

REVENUES

Revenues for the quarter were $47.1 million versus $45.3 million in the prior year period. Revenues, including realized gain on derivatives not designated as hedges of $0.1 million for the quarter, would have been $47.2 million. Average realized price per unit for the quarter, was $7.85 per Mcfe, versus $5.18 per Mcfe in the prior year period. When factoring in the realized gain on derivatives not designated as hedges, average realized price per unit was $7.88 per Mcfe, versus $6.99 per Mcfe in the prior year period.

(See accompanying tables at the end of this press release that reconciles Adjusted Revenues, a non-GAAP measure, to its most directly comparable GAAP financial measure.)

OPERATING EXPENSES

Lease operating expense ("LOE") was $7.2 million in the quarter, or $1.20 per Mcfe, versus $8.4 million, or $0.95 per Mcfe in the prior year period. LOE included $1.6 million or $0.27 per Mcfe for workovers performed in the quarter, primarily in the Eagle Ford trend.

Production and other taxes for the quarter were $2.8 million, or $0.46 per Mcfe, versus $2.0 million, or $0.23 in the prior year period, driven by higher oil volumes as a percentage of total volumes.

Transportation and processing expense was $2.6 million, or $0.43 per Mcfe in the quarter, versus $4.1 million, or $0.47 per Mcfe in the prior year period.

Depreciation, depletion and amortization ("DD&A") expense for the quarter totaled $35.0 million, or $5.84 per Mcfe, versus $32.3 million, or $3.68 per Mcfe in the prior year period. DD&A rate for the quarter was higher than the prior year due to a higher percentage of production volumes coming from oil, which carries a higher DD&A rate. DD&A expense per unit was $5.62 per Mcfe for the prior quarter.

Exploration expense was $3.3 million, or $0.56 per Mcfe for the quarter, versus $2.2 million, or $0.25 per Mcfe in the prior year period. Approximately $1.4 million or 42% of exploration expense for the quarter was associated with the expiration of undeveloped leasehold, and $0.4 million was associated with seismic expense.

General and Administrative ("G&A") expense was $9.4 million, or $1.57 per Mcfe in the quarter, versus $7.9 million, or $0.90 per Mcfe in the prior year period. The first quarter includes additional expense of $1.5 million or $0.25 per Mcfe primarily for 2012 employee bonuses paid in 2013 and increased payroll taxes. For the quarter, the Company recorded non-cash G&A expenses related to stock based compensation for its employees of $1.8 million, or $0.30 per Mcfe, versus $1.6 million, or $0.18 per Mcfe in the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $13.1 million for the quarter versus an operating loss of $14.2 million for the prior year period. Adjusted operating loss, when adjusting for realized gain on derivatives not designated as hedges was $13.0 million.

(See accompanying tables at the end of this press release that reconcile adjusted operating income, a non-GAAP financial measure to its most directly comparable GAAP financial measure.)

INTEREST EXPENSE

Interest expense for the quarter was $13.4 million, or $2.24 per Mcfe, versus $12.9 million, or $1.48 per Mcfe in the prior year period. Non-cash interest expense associated with the Company's long term debt comprised 26% of the total, or $3.4 million ($0.57 per Mcfe).

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $48.3 million, of which $46.0 million was spent on drilling and completion costs and $2.3 million on leasehold acquisition, facilities and other expenditures. Approximately 54% of the capital was spent in the Eagle Ford Shale trend, 19% in the Tuscaloosa Marine Shale trend and 27% on the completion of previously drilled Haynesville Shale wells that will be brought online in the second quarter.

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a gain of $0.1 million on its derivatives not designated as hedges and an unrealized loss of $2.1 million, for a net loss on derivatives not designated as hedges of $2.0 million for the quarter.

Subsequent to quarter end, the Company added hedges on 2,000 barrels of oil per day for 2014 at $91.98 and 10,000 MMBtu of natural gas per day for October 2013 through December 2014 at $4.18. The Company currently has 3,500 barrels of oil per day hedged for 2013 at $94.50.

LIQUIDITY

The Company exited the quarter with $4.0 million in cash and $145.0 million drawn on its senior bank revolving credit facility. Subsequent to quarter-end, the Company issued $110 million of non-convertible, perpetual preferred stock, receiving net proceeds of $106.2 million. Proforma for the preferred offering, the Company had net debt of approximately $35 million at the end of the quarter. The Company has recently received an increase in its borrowing base to $225 million, providing proforma liquidity at quarter-end of approximately $190 million.

OPERATIONAL UPDATE

For the quarter, the Company conducted drilling operations on 8 gross (3.6 net) wells, of which 5 gross (3.3 net) were in the Eagle Ford and 3 gross (1 net) were in the Tuscaloosa Marine Shale trend. A total of 8 gross (4 net) wells were added to production during the quarter, of which 3 gross (2 net) were in the Eagle Ford. As of March 31, 2013, the Company had 18 gross (10 net) wells waiting on completion, with 9 gross (4 net) in the Haynesville Shale trend and 9 gross (6 net) in the Eagle Ford Shale trend.

Tuscaloosa Marine Shale Trend ("TMS")

The Company previously reported production results on its Crosby 12H-1 (50% WI), the initial operated well completed in the field, at a 24-hour peak production rate of 1,300 BOE per day. The well has produced approximately 75,000 BOE in three months and is currently producing approximately 700 BOE per day. The Company has spud its Smith 5-29H-1 (~ 88% WI) well in Amite County, Mississippi, and currently plans to drill two additional operated wells after the Smith 5-29H-1 by the end of the year.

The Company is currently participating as a non-operator in the completion of the Ash 31H-1 (12% WI) and Ash 31H-2 (12% WI) wells in Amite County, Mississippi. The Ash 31H-1, which is a 7,000 foot lateral with 22 frac stages, is still in completion phase, and the Ash 31H-2 well, which is a 5,300 foot lateral with 18 frac stages has been flowing back for approximately two weeks and is still cleaning up due to the large frac job of one million pounds of proppant and 29,000 barrels of fluid per stage. Current 24-hour peak rate is approximately 730 BOE (92% oil) per day, with 4% of the frac fluid recovered. The Ash wells were stimulated with slick water fracs with 60-100% more frac fluid and proppant per stage than any of the prior wells drilled to date.

The Company is currently participating as a non-operator in two development wells, the Anderson 17H-2 (7% WI) and Anderson 17H-3 (7% WI) wells, both of which are in completion phase and were drilled with very little downtime. Both wells are expected to be completed within 45 days.

Eagle Ford Shale Trend, LaSalle and Frio Counties, Texas

In the Eagle Ford Shale trend, the Company conducted drilling operations on 5 gross (3.3 net) wells in the quarter, and expects to drill 24 gross (16 net) wells in 2013. In the quarter, 3 gross (two net) wells were completed, and the Company expects to complete 25 gross (16.8 net) wells for the year. The Company has reduced its drill time on recent wells by approximately 57% from the initial wells drilled in the field, to 10 days for an average 6,000 foot lateral, which along with a reduction in frac costs, has substantially decreased the well costs and increased the well count for the year.

Haynesville Shale Trend

The Company expects to complete 13 gross (5.7 net) previously drilled Haynesville Shale wells in 2013, comprised of 12 gross (4.7 net) non-operated wells in North Louisiana and 1 gross (1 net) operated well in the Angelina River trend. In the first quarter, 4 gross (1.5 net) wells were completed.

Subsequent to the first quarter, the Company completed its ACLCO No. 1H (100% WI) well in the Angelina River trend. The well continues to clean up with a current peak rate of 7,000 Mcfe per day on a restricted 15/64 inch choke with 7,775 psi with 2% of the frac fluid recovered. The Company intends to produce the well on a restricted choke program similar to its core Haynesville Shale wells in North Louisiana.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, including Adjusted EBITDAX, Discretionary cash flow, Adjusted revenues, Adjusted operating income, Adjusted net loss applicable to common stock and Cash operating margin. Management believes Adjusted EBITDAX, Discretionary cash flow, Adjusted revenues, Adjusted operating income, Adjusted net loss applicable to common stock and Cash margin are good financial indicators of the Company's ability to internally generate operating funds. None of Discretionary cash flow, Adjusted EBITDAX or Cash operating margin, should be considered an alternative to net cash provided by operating activities, as defined by GAAP. Adjusted revenues should not be considered an alternative to total revenues, as defined by GAAP. Adjusted operating income should not be considered an alternative to operating income (loss), as defined by GAAP. Adjusted net loss applicable to common stock should not be considered an alternative to net loss applicable to common stock, as defined by GAAP. 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 oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

Unless otherwise stated, oil production volumes include condensate.

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 for the year ended December 31, 2012 and other subsequent 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.

CONTACT: Main, (713) 780-9494, Fax, (713) 780-9254, Robert C. Turnham, Jr., Jan L. Schott, Chief Financial Officer