HOUSTON, Nov. 4, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced financial and operating results for the quarter ended September 30, 2013 and provided an operational update.

Tuscaloosa Marine Shale ("TMS"):

• Preliminary 2014 capital expenditure budget allocates $300 million for the TMS to drill up to 31 gross (24 net) wells with five operated rigs running in the play by the end of 2014 pending continued success
• The Company drilled its Huff 18-7H No. 1 (97% WI) well with usable lateral of approximately 5,400 feet. The Company drilled the curve and lateral in a record time of 12 days but has experienced completion delays due to temporarily sticking the drill pipe shortly after reaching total depth. The Company successfully freed the drill pipe and is currently cleaning out the wellbore in preparation of running production casing. The cleanout of the wellbore is expected to be completed withing the next few days 
• Cumulative production from the Company's Crosby well has reached 138,000 barrels of oil equivalent ("BOE", 90% oil) in 8.5 months, and five of the last six completed wells are currently producing at or above the Company's 600,000 BOE type curve (See current Management Presentation posted on website)
• The Company currently has two rigs running in the play and has commenced drilling operations on its Weyerhaeuser 51H-1 (67% WI) well in St. Helena Parish, Louisiana, the initial well of three consecutive wells planned on its recently acquired acreage block, with plans to move a rig to its CMR 8-5 (100% WI) well in Amite County, Mississippi after the Huff 18-7 well

Production:

• Production for the quarter increased by 16% sequentially to 7.7 Bcfe, or an average of 83,700 Mcfe per day. Oil volumes increased by 28% sequentially to 374,000 barrels of oil, or an average of 4,100 barrels of oil per day, while gas volumes increased by 11% sequentially to 5.5 Bcf, or an average of 59,300 Mcf per day.
• Oil production for the quarter comprised 29% of total production and 70% of revenues compared to 23% of total production and 63% of revenues in the prior year period. Average realized price per Mcfe of production was $7.38 ($6.91 including hedges), with an average oil price of $106.11 per barrel and average natural gas price of $3.15 per Mcf.

Liquidity and Balance Sheet Improvement:

• During the quarter, the Company entered into separate, privately negotiated exchange agreements under which it retired $109.25 million in aggregate principal amount of 5% Convertible Senior Notes due 2029 (the "2029 Notes"), with an initial put/call date of October 2014, in exchange for issuance of a like amount of a new series of 5.0% Convertible Senior Notes due 2032 (the "2032 Notes"), with an initial call date of October 2016 and an initial put date of October 2017. Subsequent to quarter-end the Company exchanged an additional $57.4 million of 2029 Notes for $57.0 million of 2032 Notes, leaving $51.8 million of 2029 Notes outstanding with a corresponding amount held in restricted cash.
• Borrowing base under senior credit facility increased from $243 million to $270 million.
• The Company exited the quarter with $1.9 million in cash, $109.25 million of restricted cash and $142.8 million drawn on its senior bank revolving credit facility, with a borrowing base of $243 million. Since the end of the quarter, the Company raised net proceeds of $166 million through the sale of common stock, received an increase in its borrowing base to $270 million and exchanged $57.4 million of 2029 Notes (thereby releasing a corresponding $57.4 million of restricted cash), providing proforma liquidity at quarter-end of $352.4 million. In addition, the Company has $51.8 million of restricted cash associated with the remaining 2029 Notes for a total of $404.3 million of proforma liquidity and restricted cash.

FINANCIAL RESULTS

Cash Flow

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX") was $34.7 million in the quarter compared to $48.0 million in the prior year period and $31.5 million in the prior quarter.

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital was $24.8 million in the quarter compared to $36.9 million in the prior year period and $20.9 million in the prior quarter. Net cash provided by operating activities was $5.0 million compared to $19.6 million for the prior year period.

For the prior year period, both Adjusted EBITDAX and DCF were positively impacted by a $18.8 million gain on realized derivative settlements compared to a negative impact of a $3.6 million loss 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 $32.8 million for the quarter or ($0.89) per basic share, versus net income applicable to common stock of $10.9 million or $0.30 per basic share in the prior year period. Adjusted net loss applicable to common stock was $19.9 million, which excludes the impact of the unrealized losses on derivatives not designated as hedges of $5.1 million, loss on early extinguishment of debt of $4.8 million, and lease expirations of $2.9 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 $57.2 million versus $46.0 million in the prior year period. Average realized price per unit for the quarter was $7.38 per Mcfe versus $5.92 per Mcfe in the prior year period. When factoring in the realized gain or loss on derivatives not designated as hedges, Adjusted Revenues for the quarter were $53.5 million versus $64.8 million in the prior year period and average realized price per unit was $6.91 per Mcfe versus $8.34 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 $7.1 million in the quarter or $0.92 per Mcfe versus $6.2 million or $0.80 per Mcfe in the prior year period. LOE included $1.6 million or $0.21 per Mcfe for workovers performed in the quarter, primarily in the Eagle Ford Shale trend.

Production and other taxes for the quarter were $2.5 million or $0.32 per Mcfe versus $1.7 million or $0.22 per Mcfe in the prior year period and were driven by higher oil volumes in the Eagle Ford Shale trend as a percentage of total volumes, which carry a higher severance tax rate.

Transportation and processing expense was $2.8 million, or $0.36 per Mcfe in the quarter versus $3.4 million or $0.44 per Mcfe in the prior year period.

Depreciation, depletion and amortization ("DD&A") expense for the quarter totaled $33.3 million or $4.33 per Mcfe versus $37.3 million or $4.80 per Mcfe in the prior year period, with the decline in DD&A expense per unit of production driven from higher mid-year reserves and lower capital expenditures per well in the Eagle Ford Shale trend. DD&A expense per unit was $5.18 per Mcfe for the prior quarter.

Exploration expense was $4.1 million, or $0.53 per Mcfe for the quarter versus $2.5 million or $0.32 per Mcfe in the prior year period. Approximately $3.4 million or 84% of exploration expense for the quarter was a non-cash expense for the expiration of undeveloped leasehold and amortization of the Company's undeveloped leasehold. As part of its ongoing review of capital allocation, the Company elected not to renew certain expiring leases in its non-core Eagle Ford Shale trend acreage.

General and Administrative ("G&A") expense was $8.3 million, or $1.08 per Mcfe in the quarter versus $7.1 million or $0.92 per Mcfe in the prior year period. G&A expense related to stock based compensation for its employees was $1.7 million or $0.23 per Mcfe versus $1.7 million or $0.22 per Mcfe in the prior year period.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $0.9 million for the quarter compared to operating income of $31.9 million in the prior year period. The prior year period included a gain from the sale of assets of $44.2 million. Adjusted operating loss which excludes the realized loss on derivatives not designated as hedges and the loss from extinguishment of debt was $4.8 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 $12.7 million or $1.65 per Mcfe versus $13.3 million or $1.71 per Mcfe in the prior year period. Non-cash interest expense associated with the Company's long term debt comprised 25% of the total or $3.2 million ($0.42 per Mcfe).

CRUDE OIL AND NATURAL GAS DERIVATIVES

The Company realized a loss of $3.6 million on its derivatives not designated as hedges and an unrealized loss of $5.1 million, for a loss on derivatives not designated as hedges of $8.8 million for the quarter.

CAPITAL EXPENDITURES

Capital expenditures for the quarter were $91.4 million, of which $66.3 million was spent on drilling and completion costs, $22.7 million on the Company's producing property and leasehold acquisition in the TMS and $2.4 million on other leasehold acquisitions and extensions, facilities and other expenditures. Capital expenditures for the first nine months of the year were $204.2 million, of which $174.6 million was spent on drilling and completion costs, $22.7 million primarily for the TMS acquisition, $5.9 million on acreage acquisitions and $1.0 million on facilities and other expenditures.

OPERATIONAL UPDATE

For the quarter, the Company spent approximately 32% of the capital in the Eagle Ford Shale trend, 57% in the TMS and 11% on the completion of previously drilled Haynesville Shale wells. The Company conducted drilling operations on 8 gross (6 net) wells in the quarter, including 6 gross (4 net) Eagle Ford Shale trend wells and 2 gross (1.96 net) wells in the TMS. We added 9 gross (4.87 net) wells to production in the quarter, of which 5 gross (3 net) were in the Eagle Ford Shale trend, 1 gross (0.90 net) in the TMS and 1 gross (0.50 net) in the Haynesville Shale trend. As of quarter-end, the Company had 8 gross (5.32 net) wells drilled and waiting on completion comprised of 2 gross (1 net) in the Haynesville Shale trend, 5 gross (3.33 net) in the Eagle Ford Shale trend and 1 gross (0.99 net) in the TMS.

For the year, the Company expects to drill and complete 21 gross (14 net) wells in the Eagle Ford Shale trend (down 1 gross (0.7 net) wells due to the reallocation of capital from the Eagle Ford Shale to the TMS), 9 gross (5 net) wells in the TMS and 13 gross (5.7 net) wells in the Haynesville Shale trend.

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, including Adjusted EBITDAX, DCF, Adjusted revenues, Adjusted operating income (loss), Adjusted net loss applicable to common stock and Cash operating margin. Management believes Adjusted EBITDAX, DCF, Adjusted revenues, Adjusted operating income (loss), Adjusted net loss applicable to common stock and Cash operating margin are good financial indicators of the Company's ability to internally generate operating funds. None of DCF, 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 (loss) 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