Goodrich Petroleum Announces Third Quarter Financial Results

HOUSTON, Nov. 3, 2010 /PRNewswire-FirstCall/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced its financial results for the third quarter ended September 30, 2010.

PRODUCTION

Production for the quarter was 8.4 billion cubic feet equivalent ("Bcfe"), or an average of approximately 91,700 Mcfe per day, versus 7.6 Bcfe, or an average of approximately 82,500 Mcfe per day in the prior year period, which represents an 11% increase.  Average net daily production volumes for the quarter were flat sequentially.  As of September 30, 2010, the Company had 20 gross (10 net) wells drilled and waiting on completion, which negatively affected production volumes for the quarter.

The Company expects net daily production volumes to average between 93,000 – 97,000 Mcfe per day in the fourth quarter of 2010.  Guidance does not include any potential impact from the divestiture mentioned below, which is expected to close by year-end.  

NET INCOME

Net income applicable to common stock for the quarter was a loss of $215.1 million, or ($5.98) per share, versus a loss of $31.0 million, or ($0.87) per share for the prior year period.  Net income applicable to common stock for the quarter was negatively impacted by a non-cash impairment of $223.3 million, as mentioned below.  As the Company fully valued its net deferred tax asset at the end of 2009, the Company is using an effective tax rate of zero for the full year 2010, thus there was no income tax benefit applied to the loss in the third quarter of 2010.  

CASH FLOW

Earnings before interest, taxes, DD&A and exploration expense ("EBITDAX") for the quarter was $28.1 million compared to $34.5 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 for the quarter included $6.3 million of realized gain on derivatives not qualifying as hedges in the quarter, compared to $27.2 million in the prior year period.  EBITDAX was up 5% sequentially over the second quarter of 2010 on higher realized prices and lower cash operating expenses.

Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $27.4 million in the quarter versus $30.4 million in the prior year period (see accompanying table for a reconciliation of DCF, a non-GAAP measure, to net cash provided by operating activities).  DCF increased 25% sequentially from $22.0 million for the second quarter of 2010.  Net cash provided by operating activities was $29.3 million for the quarter, up from $16.9 million in the prior year period.  DCF and net cash provided by operating activities included a realized gain of $6.3 million on natural gas derivatives in the quarter, compared to a $27.2 million realized gain on natural gas derivatives in the prior year period.

REVENUES

Total revenues for the quarter increased by approximately 59% to $37.4 million compared to $23.5 million for the prior year period.  Revenues were positively impacted by production volume growth of 11% and higher average realized prices of $4.44 per Mcfe versus $3.11 per Mcfe in the prior year period.  Total revenues and average prices received in the quarter and the prior year period do not include realized gains of $6.3 million and $27.2 million respectively, received on the Company's settled natural gas derivatives, none of which were designated as hedges.

The Company continued to positively benefit from its hedging program during the quarter.  Revenue, adjusted for the impact of net realized gains on natural gas derivatives of $6.3 million, was $43.8 million for the quarter.  Taking into account the impact of derivatives, the Company realized approximately $5.19 per Mcfe of production for the quarter (see accompanying table titled "Select Operating Data" for additional disclosure on these adjustments).

OPERATING INCOME

Operating income (loss) (defined as revenues less lease operating expense, production taxes, transportation, DD&A, exploration and general and administrative expenses), was a loss of $226.9 million for the quarter, versus a loss of $37.7 million for the prior year period.  The primary reason for the increase in operating loss from the prior year period was a non-cash $223.3 million asset impairment, as mentioned below.  Operating income (loss), adjusted for the non-cash impairment, is a loss of $3.6 million for the quarter. Operating income (loss) does not include the realized gain of $6.3 million on natural gas derivatives in the quarter.

OPERATING EXPENSES

Lease operating expense ("LOE") was $6.3 million ($0.74 per Mcfe) for the quarter versus $7.4 million ($0.97 per Mcfe) for the prior year period, which represents a decrease of 24% on a per unit basis.  Per unit LOE decreased sequentially from $0.76 per Mcfe in the second quarter of 2010.  The lower per unit LOE was primarily driven by higher per well production volumes and lower expenses from the Company's increasing Haynesville Shale production, which comprised approximately 53% of the Company's production volumes for the quarter. For 2011, subsequent to closing of the pending divestiture by year-end as discussed below, the Company expects its per unit LOE to further decrease by 15 - 25%.

Production and other taxes were $0.7 million ($.08 per Mcfe) for the quarter versus $1.3 million ($0.17 per Mcfe) for the prior year period, which represents a decrease of 53% on a per unit basis.  Per unit production and other taxes increased sequentially from $0.05 per Mcfe in the second quarter of 2010.

Transportation expense was $3.0 million ($0.35 per Mcfe) for the quarter versus $2.3 million ($0.30 per Mcfe) for the prior year period, which represents an increase of 17% on a per unit basis.  Per unit transportation expense increased sequentially from $0.26 per Mcfe in the second quarter of 2010.  Third quarter transportation expense included a non-recurring charge of $0.4 million.  

Exploration expense was $2.0 million ($0.24 per Mcfe) versus $1.6 million ($0.21 per Mcfe) for the prior year period.  Exploration expense during the third quarter of 2010 included $0.2 million in exploratory seismic costs for the Company's 3-D seismic program in the Angelina River Trend area.  Per unit exploration expense decreased 23% sequentially from $0.31 per Mcfe in the second quarter of 2010.

Depreciation, depletion and amortization ("DD&A") expense was $26.0 million ($3.09 per Mcfe) for the quarter versus $42.1 million ($5.54 per Mcfe) for the prior year period, which represents a 44% decrease on a per unit basis.  Per unit DD&A for the quarter decreased 9% sequentially, primarily due to the increased proved developed reserves in the Company's mid-year reserve report and a greater amount of production coming from the Company's lower cost Haynesville Shale properties.  As a result of the impairment expense and divestiture discussed below, the Company expects a meaningful reduction in its DD&A rate going forward.

Impairment of oil and gas properties was $223.3 million for the quarter, due to the accounting effect resulting from lower commodity futures prices at the end of the quarter, as well as the Company's change in forward looking development plans, which will focus on the Eagle Ford Shale, core Haynesville Shale in North Louisiana and the Angelina River Trend of the Shelby Trough.

General and administrative ("G&A") expense was $7.3 million ($0.86 per Mcfe) for the quarter, versus $6.8 million ($0.90 per Mcfe) for the prior year period, which represents a 4% decrease on a per unit basis. Per unit G&A for the quarter increased 2% sequentially from $0.84 per Mcfe in the second quarter of 2010.  G&A expense for both the third quarter of 2010 and the prior year period included non-cash stock based compensation of $1.5 million.

Other expense for the quarter was a gain of $4.2 million ($0.50 per Mcfe), representing reimbursement from a sub-lessee of the Company for 50% of a cash bond posted relating to a previously disclosed litigation which is currently under appeal.

INTEREST EXPENSE

Interest expense was $9.2 million for the quarter versus $6.6 million for the prior year period, with the increase due primarily to additional interest associated with the Company's 5% convertible senior notes issued in September 2009.  Of the $9.2 million in interest expense for the quarter, $4.4 million represents ongoing cash interest expense.  The remaining $4.8 million represents non-cash charges related to the amortization of debt discounts and deferred financing costs associated with the Company's convertible notes.  

DERIVATIVES

The Company recorded a gain on derivatives not designated as hedges during the quarter of $22.5 million, which includes a realized gain on natural gas derivatives of $6.3 million and an unrealized gain on natural gas derivatives of $16.2 million (see accompanying table titled "Supplementary Information" for additional disclosure on these adjustments).  As of September 30, 2010, the fair value of the Company's natural gas derivatives was $47.4 million.

LIQUIDITY

The Company exited the quarter with $12.6 million in cash and short term investments.  In October, the Company's bank group increased the borrowing base by $50 million to $250 million.  This amount will be reduced to $225 million upon closing of the $70 million divestiture discussed below.  The Company believes that its strong liquidity position, along with cash flow from operations, provides ample liquidity to fund the Company's development plans through 2011.  The combination of the increased borrowing base and proforma the closing of the asset sale, increases the Company's liquidity by $95 million to in excess $300 million as of September 30, 2010.

CAPITAL EXPENDITURES

Capital expenditures for the quarter totaled $71.2 million, compared to $41.1 million in the prior year period.  Of the $71.2 million in capital expenditures for the quarter, approximately $64.3 million, or 90% of the total was associated with the drilling and/or completion of 25 gross (11 net) wells.  Additionally, the Company spent approximately $5.4 million on leasehold acquisitions and $1.5 million on recompletions and other capital expenditures.

The Company conducted drilling operations on 21 gross (10 net) wells in the quarter, with 10 gross (6 net) wells added to production, with a 100% success rate.  As of September 30, 2010, 20 gross (10 net) wells were cased and waiting on completion, with 13 gross (5 net) wells being non-operated and 7 gross (5 net) wells being operated.

During the quarter, the Company had three operated and four non-operated rigs working in the area of East Texas, North Louisiana and South Texas.  For the remainder of the year, the Company anticipates a total of three operated rigs running, with two in East Texas and the North Louisiana region and one in the Eagle Ford Shale oil play in South Texas, along with two non-operated rigs working in North Louisiana.  

DIVESTITURE

As previously disclosed, the Company has entered into a definitive agreement to sell certain non-core shallow assets for $70 million, with closing expected by year-end.  The properties are located in the Company's Angelina River Trend and Bethany Longstreet areas, with all deep rights reserved, including the rights to the Haynesville Shale and Bossier Shale.  Proved reserves for the assets being sold at mid-year under SEC pricing were approximately 37 Bcfe, with expected production of approximately 12,000 Mcf per day at closing.

ANGELINA RIVER TREND / SHELBY TROUGH – LEASEHOLD ACQUISITION

As previously disclosed, the Company has acquired an additional 5,000 net acres near its recent Haynesville Shale discovery with the SW Henderson No. 1H well in Nacogdoches and Angelina Counties, Texas.  The Company paid an average price of approximately $650 per acre.

MANAGEMENT COMMENTS

Commenting on the third quarter results, Walter G. "Gil" Goodrich, Vice-Chairman and CEO stated, "We are off to a good start on our two emerging plays, the Shelby Trough and Eagle Ford Shale.  As we continue our delineation process through the remainder of this year, we expect these two plays will be the focus of, and receive the majority of our development capital, during 2011.  We believe our position in Shelby Trough, which is prospective for both the Haynesville and Upper Bossier Shale, will provide us with enhanced production growth per dollar invested as we go forward.  We also believe our Eagle Ford Shale position, which is prospective for both the Eagle Ford Shale and Buda Lime formations, will allow us to rapidly grow our crude oil and liquids production and significantly enhance our net cash flow per Mcfe of production in 2011.  In addition, the increases in both our mid-year proved reserves and our recently redetermined borrowing base illustrate the success of our development activities in the core Haynesville Shale.  The increased liquidity in the borrowing base and the pending non-core asset sale, as well as the reduction in both operated and non-operated gas-directed drilling activity, will provide significant incremental financial flexibility to execute our development plans in 2011."

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.

SOURCE Goodrich Petroleum Corporation

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