HOUSTON, Aug. 6, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the quarter ended June 30, 2013 and provided an operational update.

• Tuscaloosa Marine Shale ("TMS"):
  • The Encana operated Anderson 17H-2 (7% WI) well is online and producing with a peak 24-hour average rate of 1,540 BOE (95% oil) on a 17/64 inch choke.  The Anderson 17H-3 (7% WI) well is in early stage of flowback with approximately 2% of frac fluid recovered, with results to be announced upon achievement of peak rate;
  • The Smith 5-29H-1 (89% WI) well has averaged approximately 1,000 BOE (96% oil) per day on a 12/64 inch choke over the last eight days;
  • The Crosby 12H-1 (50% WI) well reached cumulative production of in excess of 100,000 BOE in five months, with current production rate of approximately 375 BOE per day;
  • Company on target to close by August 22^nd on its recently announced acquisition of a 66.7% working interest in 750 gross barrels of oil per day (March 2013) and 277,000 gross acres for $26.7 million, effective March 1, 2013. Upon closing, the Company will own approximately 320,000 net acres in the TMS;
  • The Company has reallocated approximately $15 million of estimated capital expenditures from its Eagle Ford Shale 2013 capital expenditure budget to accelerate development of its new TMS acreage block in the fourth quarter with further acceleration anticipated in 2014.  
• Production for the quarter was 6.7 billion cubic feet equivalent ("Bcfe"), or an average of 73,200 Mcfe per day, versus 8.3 Bcfe or an average of 91,000 Mcfe per day in the prior year period. Average daily production for the quarter grew 10% sequentially.  Oil production for the quarter totaled 292,000 barrels of oil or an average of 3,209 barrels per day, versus 254,000 barrels of oil or 2,791 barrels per day, in the prior year period.  Natural gas production for the quarter totaled 4.9 Bcf or an average of 54,000 Mcf per day.  Oil production in the Eagle Ford Shale trend continued to be impacted by frac interference as the Company has been concentrating its development activities on a portion of its acreage with pad drilled wells and zipper fracs.  Frac interference is subsiding as the Company has moved its rig to an area where it expects less interference, with current oil production for the Company in the 4,300 to 4,500 barrels per day range.
• Oil volumes comprised 26% of total production and 62% of revenues for the quarter as average daily natural gas volumes increased 18% sequentially, with average realized oil price of $101.62 per barrel due to premium pricing agreements. Average realized price per Mcfe of production was $7.23 per Mcfe, including realized gain on derivatives.

FINANCIAL RESULTS

Cash Flow

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") was $31.5 million in the quarter compared to $45.2 million in the prior year period and $27.1 million in the prior quarter.

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital was $20.9 million in the quarter compared to $34.8 million in the prior year period and $16.3 million in the prior quarter. Net cash provided by operating activities was $29.6 million compared to $47.4 million for the prior year period.

For the prior year period, both Adjusted EBITDAX and DCF were positively impacted by a $21.3 million gain on realized derivative settlements compared to a $0.1 million gain in the current quarter.

(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 $20.1 million for the quarter or ($0.55) per basic share, versus a net loss applicable to common stock of $4.7 million or ($0.13) per basic share in the prior year period. Adjusted net loss applicable to common stock was $23.0 million, which excludes the impact of the unrealized gain on derivatives not designated as hedges of $11.0 million, non-recurring exploration expense of $0.6 million and lease expirations of $7.5 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.)

REVENUES

Revenues for the quarter were $48.5 million versus $41.3 million in the prior year period. Average realized price per unit for the quarter was $7.22 per Mcfe versus $5.00 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 $7.23 per Mcfe versus $7.58 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 $5.9 million in the quarter or $0.88 per Mcfe versus $6.7 million or $0.81 per Mcfe in the prior year period. LOE included $1.1 million or $0.17 per Mcfe for workovers performed in the quarter primarily in the Eagle Ford Shale trend.

Production and other taxes for the quarter were $2.7 million or $0.41 per Mcfe versus $2.1 million or $0.25 per Mcfe in the prior year period driven by higher oil volumes as a percentage of total volumes which carries a higher severance tax rate.

Transportation and processing expense was $2.5 million, or $0.37 per Mcfe in the quarter versus $3.5 million or $0.43 per Mcfe in the prior year period.

Depreciation, depletion and amortization ("DD&A") expense for the quarter totaled $34.5 million or $5.18 per Mcfe versus $34.6 million or $4.17 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 properties carry a higher DD&A rate. DD&A expense per unit was $5.84 per Mcfe for the prior quarter.

Exploration expense was $9.5 million, or $1.43 per Mcfe for the quarter versus $2.0 million or $0.24 per Mcfe in the prior year period. Approximately $7.5 million or 78% of exploration expense for the quarter was a non-cash expense for the expiration of undeveloped leasehold. As part of its ongoing review of capital allocation, the Company elected not to renew expiring leases in its non-core Eagle Ford Shale trend acreage. Exploration expense for the quarter also includes $0.6 million in seismic expense.

General and Administrative ("G&A") expense was $7.6 million, or $1.15 per Mcfe in the quarter versus $6.7 million or $0.81 per Mcfe in the prior year period. G&A expense related to stock based compensation for its employees was $1.7 million or $0.26 per Mcfe versus $1.5 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 $14.2 million for the quarter in line with the prior year period. Adjusted operating loss which includes the realized gain on derivatives not designated as hedges was a loss of $14.1 million.

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

INTEREST EXPENSE

Interest expense for the quarter was $13.0 million or $1.96 per Mcfe versus $13.1 million or $1.58 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 ($0.51 per Mcfe).

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $64.5 million, of which $62.4 million was spent on drilling and completion costs and $2.1 million on leasehold acquisition, facilities and other expenditures. Approximately 60% of the capital was spent in the Eagle Ford Shale trend, 17% in the Tuscaloosa Marine Shale trend and 23% on the completion of previously drilled Haynesville Shale wells that were 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 gain of $11.0 million, for a gain on derivatives not designated as hedges of $11.1 million for the quarter.

LIQUIDITY

The Company exited the quarter with $2.7 million in cash and $75.0 million drawn on its senior bank revolving credit facility, with a borrowing base of $225 million, providing $152.7 million of available liquidity. Upon closing of the TMS acquisition the Company's borrowing base will increase by $18 million to $243 million.

PRODUCTION GUIDANCE

The Company is revising its full year 2013 production guidance to incorporate the experienced frac interference in its Eagle Ford Shale trend development drilling and delays due to a reallocation of capital from the Eagle Ford Shale to the TMS. The Company currently estimates oil volumes will grow by 30-40% in 2013 versus 2012 and overall volumes on a Mcfe basis will decrease by 5-10% year over year. Oil volumes are estimated to comprise approximately 30% of total production and 65-70% of revenues for the year.

OPERATIONAL UPDATE

Tuscaloosa Marine Shale ("TMS"):

The Company drilled and/or completed 4.0 gross (1.2 net) wells in the TMS in the quarter and expects to drill and complete 9.0 gross (4.6 net) wells in the trend for the year. The Company had 3.0 gross (1.1 net) wells waiting on completion at quarter-end.

The Company is currently drilling its CMR/Foster Creek 20-7H-1 (99% WI) well in Wilkinson County, Mississippi and currently plans to spud three additional operated wells by the end of the year. The Company has reallocated approximately $15 million of its 2013 capital expenditure budget from the Eagle Ford Shale to accelerate development of its new TMS acreage block.

Eagle Ford Shale:

The Company conducted drilling operations on 7.0 gross (4.7 net) wells in the quarter and expects to drill 22.0 gross (14.7 net) wells for the year. In the quarter 9.0 gross (6.0 net) wells were completed and added to production, with 12.0 gross (8.0 net) wells completed and added to production year to date. For the year the Company expects to complete 22.0 gross (14.7 net) wells, down 3.0 gross (2.0 net) due to the reallocation of capital from the Eagle Ford Shale to the TMS. At quarter-end, 5.0 gross (3.3 net) wells were drilled but waiting on completion.

The Company has reduced its average drill time from inception by 13 days targeting 6,000 foot laterals which has led to a sharp reduction in costs over time, however, oil production for the quarter continued to be affected by frac interference due to pad drilling on a portion of the Company's Eagle Ford Shale acreage.

Haynesville Shale

The Company completed 6.0 gross (2.7 net) previously drilled Haynesville Shale wells in the quarter with 10.0 gross (4.2 net) wells completed and added to production year to date. The Company had 3.0 gross (1.5 net) wells drilled but waiting on completion at quarter-end. For the year, the Company expects to complete 13.0 gross (5.7 net) wells, with the remainder expected to be completed by the end of the third quarter.

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: Robert C. Turnham, Jr., President, or Jan L. Schott, Chief Financial Officer, (713) 780-9494, fax, (713) 780-9254