Goodrich Petroleum Announces Second Quarter Financial and Operational Results

  • Net Production Volumes for the Quarter Increased by 12% Over the Prior Year Period and 4% Sequentially to an Average of 92,000 Mcfe per Day
  • Per Unit Lease Operating Expense (LOE) for the Quarter Decreased by 19% Versus the Prior Year Period and 16% Sequentially to $0.76 per Mcfe. Total Recurring Per Unit Operating Expense Reduced by 27% from the Prior Year Period and 13% Sequentially
  • EBITDAX for the Quarter Increased by 12% Sequentially to $26.9 Million
  • Haynesville Shale (Shelby Trough)
  • Initial Well in Nacogdoches/Angelina County area, the SW Henderson 1H, encountered 215 feet of Haynesville Shale and 200 feet of Bossier Shale Prospective
  • Initial Well in Shelby County, the R. Dean 1H, encountered 126 feet of Haynesville Shale and 188 feet of Bossier Shale Prospective
  • Eagle Ford Shale Play
  • Initial Well Completed in the Buda Lime Formation with a 24-Hour Initial Production Rate of 530 Barrels of Oil Equivalent (BOE) Per Day, and a 30-day Average Rate of 435 BOE per day
  • Initial Well in the Eagle Ford Shale, the Pan Am B 1H in Completion Phase
  • Company Maintains its $255 Million Capital Expenditure Budget, with Current Liquidity of $256 Million

HOUSTON  (Profitable.com)  Goodrich Petroleum Corporation (NYSE: GDP) today announced its financial and operating results for the second quarter ended June 30, 2010.

PRODUCTION

Net production volumes in the quarter increased by 12% to 8.4 billion cubic feet equivalent (“Bcfe”), or an average of approximately 92,000 Mcfe per day, versus 7.5 Bcfe, or an average of approximately 82,100 Mcfe per day in the prior year period.  Average net daily production volumes for the quarter increased 4% sequentially.  During the second quarter, the Company completed and added 8 gross (4 net) wells to production compared to 6 gross (2 net) wells during the first quarter.

The Company expects net daily production volumes to average between 94,000 – 98,000 Mcfe per day in the third quarter of 2010.

NET INCOME

Net income applicable to common stock for the quarter was a loss of $23.1 million, or ($0.64) per share, versus a loss of $36.5 million, or ($1.02) per share for the prior year period.  During the quarter, net income applicable to common stock was positively impacted by both higher production volumes and lower operating costs relative to the prior year period.  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 second quarter of 2010.

CASH FLOW

Earnings before interest, taxes, DD&A and exploration (“EBITDAX”) for the quarter, decreased by 28% to $26.9 million compared to $37.3 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 up 12% sequentially over the first quarter of 2010 on increased production volumes and lower operating costs.

Discretionary cash flow (“DCF”), defined as net cash provided by operating activities before changes in working capital, decreased by 34% to $22.0 million in the quarter from $33.0 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 114% sequentially from $10.2 million reported during the first quarter of 2010.  Net cash provided by operating activities was $28.9 million for the quarter, up from $27.1 million in the prior year period.  DCF and net cash provided by operating activities included a realized gain of $7.7 million on natural gas derivatives in the second quarter of 2010, compared to the $27.2 million realized gain on natural gas derivatives in the prior year period.

REVENUES

Total revenues for the quarter increased by approximately 30% to $34.2 million compared to $26.3 million for the prior year period.  Revenues were positively impacted by production volume growth of 12% over the prior year period and higher realized prices of $4.07 per Mcfe versus $3.51 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 $7.7 million and $27.2 million respectively, received on the Company’s settled natural gas derivatives, none of which were designated as hedges during the second quarters of 2010 and 2009.

The Company continued to positively benefit from its hedging program during the second quarter.  Revenue, adjusted for the impact of net realized gains on natural gas derivatives of $7.7 million, for the second quarter of 2010 was $41.9 million.  Taking into account the impact of derivatives, the Company realized approximately $4.98 per Mcfe of production for the second quarter of 2010 (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 $12.8 million for the quarter, versus a loss of $53.9 million for the prior year period.  The primary reason for the decrease in operating loss from the prior year period was increased revenue, coupled with lower lease operating expense, production taxes, transportation expense, as well as a 31% reduction in per unit DD&A expense.  Operating income (loss) during the prior year period was negatively impacted by a $23.5 million asset impairment.  Operating income (loss) does not include the realized gain of $7.7 million on natural gas derivatives in the quarter.

OPERATING EXPENSES

Lease operating expense (“LOE”) decreased by 9% to $6.3 million in the quarter versus $7.0 million in the prior year period.  LOE decreased by 19% on a per unit basis to $0.76 per Mcfe in the quarter from $0.94 per Mcfe in the prior year period.  Sequentially, per unit LOE decreased by 16% compared to $0.91 per Mcfe in the first quarter of 2010.  The lower per unit LOE was primarily driven by reduced salt water disposal and compression costs, as well as higher per well production volumes and lower costs from the Company’s increasing Haynesville Shale production, which comprised approximately 50% of the Company’s production volumes for the second quarter of 2010.

Production and other taxes decreased by 63% to $0.4 million in the quarter versus $1.0 million in the prior year period. Production and other taxes decreased by 64% on a per unit basis to $0.05 per Mcfe in the quarter from $0.14 per Mcfe in the prior year period.  Per unit production and other taxes decreased 58% sequentially from $0.12 per Mcfe in the first quarter of 2010.

Transportation expense decreased by 16% to $2.2 million in the quarter versus $2.6 million in the prior year period.  Transportation expense decreased by 26% on a per unit basis to $0.26 per Mcfe in the quarter from $0.35 per Mcfe in the prior year period.  Per unit transportation expense decreased 16% sequentially from $0.31 per Mcfe in the first quarter of 2010.

Depreciation, depletion and amortization (“DD&A”) expense decreased to $28.4 million ($3.39 per Mcfe) for the quarter from $36.5 million ($4.89 per Mcfe) from the prior year period, which represents a 31% decrease on a per unit basis.  Per unit DD&A for the quarter decreased 11% sequentially, primarily due to a greater amount of production coming from the Company’s lower cost Haynesville Shale properties.

Exploration expense decreased by 11% to $2.6 million versus $3.0 million in the prior year period.  Exploration expense during the second quarter of 2009 included early termination fees of $1.1 million for two drilling rigs.  The impact of this decrease during the current period was partially offset by $0.4 million in exploratory seismic costs for the Company’s 3-D seismic program in the Angelina River Trend area.  Per unit exploration expense decreased sequentially by 16% to $0.31 per Mcfe.

General and administrative (“G&A”) expenses totaled $7.0 million for the quarter, or $0.84 per Mcfe, versus $6.7 million, or $0.90 per Mcfe, during the prior year period.  Per unit G&A decreased by 7% over the prior year period and 29% sequentially.  On a sequential basis, G&A expense was lower primarily due to additional expenses for bonus payments and the resignation of an officer during the previous quarter.  G&A expenses for the second quarter of 2010 included $1.5 million of non-cash stock based compensation costs compared to $1.6 million during the prior year period.

INTEREST EXPENSE

Interest expense increased to $9.2 million in the quarter from $5.3 million in the prior year period, 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, only $4.5 million represents ongoing cash interest expense.  The remaining $4.7 million represents non-cash charges related to the amortization of debt discounts and deferred financing costs associated with the Company’s convertible notes (as required by APB 14-1), resulting in a reduction of $55.4 million in long term debt on the balance sheet as of June 30, 2010.

DERIVATIVES

The Company recorded a gain on derivatives not designated as hedges during the second quarter of 2010 of $0.3 million, which includes a realized gain on natural gas derivatives of $7.7 million and an unrealized loss on natural gas derivatives of $7.4 million.  The second quarter also includes a realized loss of $0.5 million and an unrealized gain of $0.5 million on the Company’s interest rate swap which ended in April 2010 (see accompanying table titled “Supplementary Information” for additional disclosure on these adjustments).

LIQUIDITY

The Company exited the quarter with $56.5 million in cash and short term investments and $200 million of available borrowing capacity under its bank credit facility.  The Company believes that its strong liquidity position of $256 million, along with cash flow from operations, provides ample liquidity to fund the Company’s development plans through 2011.

CAPITAL EXPENDITURES

Capital expenditures for the quarter totaled $80.0 million, compared to $65.3 million in the prior year period.  Of the $80.0 million in capital expenditures for the quarter, approximately $56.6 million, or 71% of the total was associated with the drilling and/or completion of 22 gross (12 net) wells.  Additionally, the Company spent approximately $21.5 million on leasehold acquisitions (with approximately $20.0 million spent in the Eagle Ford Shale play) and $1.9 million on recompletions and other capital expenditures.

The Company conducted drilling operations on 15 gross (9 net) wells in the quarter, with 8 gross (4 net) wells added to production, with a 100% success rate.  As of June 30, 2010, 14 gross (7 net) wells were cased and waiting on completion.

During the quarter, the Company had three operated and four non-operated rigs working in the area of East Texas and North Louisiana.  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.

OTHER – LITIGATION UPDATE

In the first quarter of 2010, the Company accrued $8.5 million in expense related to a judgment in a case filed in Louisiana state court in Caddo Parish, Louisiana.  The case involves a dispute over the interpretation of a “most favored nations” provision and a separate oil and gas lease taken by a sub-lessee of the Company.  Subsequent to the end of the second quarter, the Company and the sub-lessee executed an agreement whereby the sub-lessee agreed to reimburse the Company for one-half of any sums for which the Company may be cast in judgment in this lawsuit in any final non-appealable judgment, and further agreed to reimburse the Company for 50% of the cash bond posted on appeal.  The effect will be a $4.25 million credit to the Company in the third quarter of 2010 for the previously taken expense during the first quarter of 2010.

OPERATIONAL UPDATE

The Company conducted drilling operations on 15 gross (9 net) wells in the quarter, with 8 gross (4 net) wells added to production, with a 100% success rate.  As of June 30, 2010, the Company’s backlog of net wells drilled and waiting on completion increased sequentially to 14 gross (7 net) wells.

Haynesville Shale – Shelby Trough

The Company has drilled and logged its SW Henderson 1H (100% WI) well in Angelina County, Texas, with an estimated 215 feet of Haynesville Shale and 200 feet of Bossier Shale prospective in the well.  The Company is currently drilling the lateral and is anticipating completing the well in early September.

The Company has also drilled and logged its R Dean 1H (80% WI) well in Shelby County, Texas, with an estimated 126 feet of Haynesville Shale and 188 feet of Bossier Shale prospective.  The Company has reached total depth on the lateral in the Haynesville Shale and is currently moving the rig to drill its R Dean 2H (80% WI), which it anticipates will be its initial Bossier Shale completion.

South Texas Eagle Ford Shale Oil Play

As previously announced, the Company has entered into agreements to acquire approximately 50,000 gross (35,000 net) acres in the oil window of the Eagle Ford Shale play in LaSalle and Frio Counties, Texas.  Currently, the Company estimates its acreage position in the play at approximately 37,500 net acres.  The Company has drilled or participated in the drilling of the Goodrich Petroleum Company – Pan Am B 1H, formerly known as the Francis Shiner B-1 (80% WI), and the Blackbrush Oil & Gas – Pals Ranch 9H (50% WI) targeting the Buda Lime formation, which sits directly below the Eagle Ford Shale.  The Pan Am B-1H, which is a horizontal Eagle Ford Shale well with a lateral length of approximately 4,700 feet, is currently in completion phase.  The Pals Ranch 9H was completed without stimulation as an open-hole completion with an initial 24-hour production rate of 530 BOE (77% oil) and a 30-day average rate of 435 BOE/day.  By year-end, the Company expects to have conducted drilling operations on approximately four gross wells targeting the Eagle Ford Shale and three gross wells targeting the Buda Lime formation.

South Henderson: Cotton Valley Taylor Sand Play

The Company has drilled and completed its Pone 6H horizontal well in the Taylor Sand.  The well was drilled with a lateral of approximately 4,200′, however, the well experienced numerous mechanical problems during the completion phase and as a result, the well is currently only producing from approximately 19% of the lateral.  The well is in early stages of flow back at a current rate of 1,000 Mcf per day on a 21/64 inch choke with 665 psi.  The Company’s second horizontal Cotton Valley Taylor Sand well in the South Henderson Field, the Goodrich Petroleum Company – Craig 2H, is expected to spud in late August 2010.

MANAGEMENT COMMENTS

Commenting on the second quarter results, Walter G. “Gil” Goodrich, Vice-Chairman and CEO stated, “During the second quarter, we made tremendous progress on almost every front.  Our initial delineation efforts in both the Eagle Ford Shale and Shelby Trough are extremely encouraging and we anticipate positive follow-on results in the coming months.  Our core Haynesville Shale activities again delivered outstanding results, which lead to very strong production growth in the quarter.  In addition, we had an exceptional quarter on reducing per unit operating costs across the board, led by a 16% sequential decline in lease operating expense and an 11% decline in DD&A due primarily to our attractive finding cost in the Haynesville Shale.  Even in the current environment, we are confident we will deliver solid growth and additional asset value creation in the second half of the year.”

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.

GOODRICH PETROLEUM CORPORATION  
Selected Income Data  
(In Thousands, Except Per Share Amounts)  
(Unaudited)  
 
Three Months Ended Six Months Ended  
June 30, June 30,  
2010 2009 2010 2009  
 
Total Revenues $  34,162 $  26,263 $  74,617 $  54,724  
 
Operating Expenses  
Lease operating expense 6,329 6,984 13,561 15,980  
Production and other taxes 390 1,049 1,353 2,537  
Transportation 2,189 2,591 4,642 5,179  
Depreciation, depletion and amortization 28,403 36,537 58,616 70,195  
Exploration 2,627 2,959 5,606 5,179  
Impairment of oil and gas properties 23,490 23,490  
General and administrative 7,001 6,713 16,447 13,770  
Gain on sale of assets (113) (113)  
Other 8,500  
 
Operating loss (12,777) (53,947) (34,108) (81,493)  
 
Other income (expense)  
Interest expense (9,195) (5,298) (18,315) (10,506)  
Interest income and other 53 202 106 448  
Gain on derivatives not designated as hedges 320 2,556 35,049 39,562  
 
(8,822) (2,540) 16,840 29,504  
 
Loss before income taxes (21,599) (56,487) (17,268) (51,989)  
Income tax benefit 21,505 20,151  
Net loss (21,599) (34,982) (17,268) (31,838)  
 
Preferred stock dividends 1,512 1,512 3,024 3,024  
 
Net loss applicable to common stock $ (23,111) $ (36,494) $ (20,292) $ (34,862)  
 
Per Common Share  
Net loss applicable to common stock – basic $     (0.64) $     (1.02) $     (0.57) $     (0.97)  
Net loss applicable to common stock – diluted $     (0.64) $     (1.02) $     (0.57) $     (0.97)  
 
Weighted average common shares outstanding – basic 35,918 35,937 35,888 35,953  
Weighted average common shares outstanding – diluted 35,918 35,937 35,888 35,953  
                 
GOODRICH PETROLEUM CORPORATION  
Selected Cash Flow Data (In Thousands)  
(Unaudited)  
 
Three Months Ended Six Months Ended  
June 30, June 30,  
2010 2009 2010 2009  
 
Calculation of EBITDAX:  
Revenue $ 34,162 $ 26,263 $ 74,617 $ 54,724  
Lease operating expense (6,329) (6,984) (13,561) (15,980)  
Production and other taxes (390) (1,049) (1,353) (2,537)  
Transportation (2,189) (2,591) (4,642) (5,179)  
G&A – cash portion only (5,521) (5,141) (12,458) (10,567)  
Realized gain on derivatives not designated as hedges 7,135 26,801 8,220 47,827  
 
EBITDAX $ 26,868 $ 37,299 $ 50,823 $ 68,288  
 
Reconciliation of EBITDAX to Net Cash Provided by Operating Activities:  
EBITDAX $ 26,868 $ 37,299 $ 50,823 $ 68,288  
Exploration (2,627) (2,959) (5,606) (5,179)  
Prospect amortization 1,585 1,377 3,190 2,901  
Exploration non-cash 530 1,005 101  
Interest expense (4,449) (2,924) (8,820) (5,885)  
Interest income and other 53 202 106 448  
Other expense (8,500)  
Current Income taxes 31 35  
Net changes in working capital 6,926 (5,910) 15,455 2,664  
 
Net cash provided by operating activities (GAAP) $ 28,886 $ 27,116 $ 47,653 $ 63,373  
 
Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities:  
Discretionary cash flow $ 21,960 $ 33,026 $ 32,198 $ 60,709  
Net changes in working capital 6,926 (5,910) 15,455 2,664  
 
Net cash provided by operating activities (GAAP) $ 28,886 $ 27,116 $ 47,653 $ 63,373  
 
 
Selected Operating Data:  
Three Months Ended Six Months Ended  
June 30, June 30,  
2010 2009 2010 2009  
Production:  
Natural gas (MMcf) 8,187 7,223 15,967 13,768  
Oil and condensate (MBbls) 31 41 64 86  
Total (Mmcfe) 8,373 7,469 16,351 14,287  
 
Average realized prices per unit:  
Oil (per Bbl) $   73.21 $   52.98 $   74.64 $   42.75  
Natural gas (per Mcf):  
  Including realized gain on natural gas derivatives 4.82 7.09 4.95 7.21  
  Excluding realized gain on natural gas derivatives 3.88 3.33 4.36 3.70  
Natural gas and oil (per Mcfe):  
  Including realized gain on natural gas derivatives 4.98 7.15 5.13 7.21  
  Excluding realized gain on natural gas derivatives 4.07 3.51 4.55 3.83  
 
Expenses per Mcfe:  
Lease operating expense $     0.76 $     0.94 $     0.83 $     1.12  
Production and other taxes 0.05 0.14 0.08 0.18  
Transportation 0.26 0.35 0.28 0.36  
DD&A 3.39 4.89 3.58 4.91  
Exploration 0.31 0.40 0.34 0.36  
Impairment of oil and gas properties 3.14 1.64  
General and administrative 0.84 0.90 1.01 0.96  
Gain on sale of assets (0.02) (0.01)  
Other 0.52  
                 
GOODRICH PETROLEUM CORPORATION  
Supplementary Data (In Thousands, Except Per Share Amounts)  
(Unaudited)  
 
Supplementary information:  
Three Months Ended Six Months Ended  
June 30, June 30,  
2010 2009 2010 2009  
 
Natural gas derivatives not designated as hedges:  
   Realized gain $    7,686 $  27,189 $     9,329 $   48,324  
   Unrealized gain (loss) (7,363) (24,380) 25,742 (8,370)  
Interest rate derivatives not designated as hedges:  
   Realized loss $      (551) $      (388) $   (1,109) $      (497)  
   Unrealized gain   548 135 1,087 105  
Gain on derivatives not designated as hedges (GAAP) $       320 $    2,556 $   35,049 $   39,562  
 
Cash interest expense $    4,449 $    2,924 $     8,820 $     5,885  
Amortization of debt discount and finance costs 4,746 2,374 9,495 4,621  
Interest expense (GAAP) $    9,195 $    5,298 $   18,315 $   10,506  
 
Cash general and administrative expense $    5,521 $    5,141 $   12,458 $   10,567  
Stock based compensation (non-cash) 1,480 1,572 3,989 3,203  
General and administrative expense (GAAP) $    7,001 $    6,713 $   16,447 $   13,770  
 
Net income (loss) adjusted for non-recurring items below $ (15,856) $  11,128 $ (35,999) $   (3,220)  
Unrealized gain (loss) on derivatives not designated as hedges (6,815) (24,245) 26,829 (8,265)  
Other – Hoover Tree Farm ruling litigation (8,500)  
G&A – resignation of an officer of the company (867)  
G&A – additional 2009 bonus paid in March 2010 (875)  
Exploration – Angelina River Trend 3-D seismic (440) (880)  
Gain on sale of assets 113 113  
Impairment of oil and gas properties (23,490) (23,490)  
Net loss applicable to common stock (GAAP) $ (23,111) $ (36,494) $ (20,292) $ (34,862)  
 
Per Common Share (basic):  
Net loss adjusted for non-recurring items below $     (0.44) $      0.31 $     (1.00) $     (0.09)  
Unrealized gain (loss) on derivatives not designated as hedges (0.19) (0.68) 0.74 (0.23)  
Other – Hoover Tree Farm litigation (0.25)  
G&A – resignation of an officer of the company (0.02)  
G&A – additional 2009 bonus paid in March 2010 (0.02)  
Exploration – Angelina River Trend 3-D seismic (0.01) (0.02)  
Gain on sale of assets  
Impairment of oil and gas properties (0.65) (0.65)  
Net loss applicable to common stock (GAAP) $     (0.64) $     (1.02) $     (0.57) $     (0.97)  
 
Per Common Share (diluted):  
Net income adjusted for non-recurring items below $     (0.44) $      0.31 $     (1.00) $     (0.09)  
Unrealized gain (loss) on derivatives not designated as hedges (0.19) (0.68) 0.74 (0.23)  
Other – Hoover Tree Farm litigation (0.25)  
G&A – resignation of an officer of the company (0.02)  
G&A – additional 2009 bonus paid in March 2010 (0.02)  
Exploration – Angelina River Trend 3-D seismic (0.01) (0.02)  
Gain on sale of assets  
Impairment of oil and gas properties (0.65) (0.65)  
Net income applicable to common stock (GAAP) $     (0.64) $     (1.02) $     (0.57) $     (0.97)  
 
Operating expense adjusted for non-recurring items below $  46,499 $  56,833 $   97,603 $ 112,840  
Other – Hoover Tree Farm ruling litigation 8,500  
G&A – resignation of an officer of the company 867  
G&A – additional 2009 bonus paid in March 2010 875  
Exploration – Angelina River Trend 3-D seismic 440 880  
Gain on sale of assets (113) (113)  
Impairment of oil and gas properties 23,490 23,490  
Operating expense (GAAP) $  46,939 $  80,210 $ 108,725 $ 136,217  
 
Operating loss adjusted for non-recurring items below $ (12,337) $ (30,570) $ (22,986) $ (58,116)  
Other – Hoover Tree Farm ruling litigation (8,500)  
G&A – resignation of an officer of the company (867)  
G&A – additional 2009 bonus paid in March 2010 (875)  
Exploration – Angelina River Trend 3-D seismic (440) (880)  
Gain on sale of assets 113 113  
Impairment of oil and gas properties (23,490) (23,490)  
Operating loss (GAAP) $ (12,777) $ (53,947) $ (34,108) $ (81,493)