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| 8-K - GOODRICH PETROLEUM CORP | v230791_8k.htm |
Goodrich Petroleum Announces Second Quarter Financial and Operational Results
-- CASH FLOW GROWTH: Adjusted EBITDAX for the quarter was $43.7 million, an increase of 63% from the prior year period and 30% sequentially, driven by increased oil volumes and lower operating costs. Discretionary cash flow was $33.3 million for the quarter, an increase of 24% sequentially
-- PRODUCTION VOLUME GROWTH: Production for the quarter increased by 23% from the prior year period, and 12% sequentially to an average of 113,300 Mcfe per day. Oil volumes grew sequentially by 67% to approximately 1,500 barrels of oil per day, which comprised approximately 8% of total production and 25% of total revenue
-- PRODUCTION GUIDANCE AND CAPITAL EXPENDITURE BUDGET: Production is expected to average 115,000 – 118,000 Mcfe per day in the third quarter of 2011, with oil production expected to comprise approximately 12 – 15% of total volumes, or an average of 2,400 – 2,800 barrels of oil per day. Production guidance for the year is being increased to an average 108,000 – 112,000 Mcfe per day, or an increase of 15 – 25% over 2010, versus the prior guidance of 10 – 20% growth. The 2011 capital expenditure budget is being increased 34% to $315 million from $235 million to reflect a 35% increase in the number of net wells drilled during the year, an increased leasehold acquisition budget for the Tuscaloosa Marine Shale and completion cost escalation. Of the 35% increase in number of net wells drilled for the year, 62% of the increase is associated with non-operated properties
-- COST STRUCTURE LOWER: Per unit operating costs for the quarter were lower by 12% versus the prior year period as follows:
- Lease operating expense ("LOE") decreased by 33% from the prior year period and 6% sequentially to $0.51 per Mcfe
- Transportation expense decreased by 15% from the prior year period and 15% sequentially to $0.22 per Mcfe
- Exploration expense decreased by 26% from the prior year period and 15% sequentially to $0.23 per Mcfe
- Depreciation, depletion and amortization ("DD&A") expense decreased by 12% from the prior year period and increased by 9% sequentially to $3.00 per Mcfe
- General and administrative ("G&A") expense decreased by 15% from the prior year period and 22% sequentially to $0.71 per Mcfe
-- HEDGING: The Company incurred a realized gain on its derivatives not designated as hedges of $6.0 million and an unrealized gain of $5.0 million for a gain of $11.0 million for the quarter. The realized gain of $6.0 million for the quarter is not shown in revenue due to the derivatives not being designated as hedges
-- OPERATIONAL UPDATE: The Company announced the following key well results added during the quarter (rates reflect peak 24-hour production):
- Eagle Ford Shale:
* Burns Ranch 15H – 1,250 BOE per day (1,155 BO and 570 Mcf per day);
* Burns Ranch 17H – 1,155 BOE per day (1,108 BO and 280 Mcf per day);
* Burns Ranch 18H – 1,030 BOE per day (955 BO and 450 Mcf per day)
- Buda Lime:
* Carnes 6H – 1,635 BOE per day (1,380 BO and 1,535 Mcf per day), with a 30-day average of 1,000 BOE per day (69% oil)
- Cotton Valley Taylor Sand:
* Craig 4H – 9,360 Mcfe per day, comprised of 8,400 Mcf and 160 BO per day
HOUSTON, Aug. 3, 2011 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced its financial and operating results for the second quarter ended June 30, 2011.
CASH FLOW
Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("Adjusted EBITDAX"), increased by 63% to $43.7 million for the quarter, compared to $26.9 million in the prior year period (see accompanying table for a reconciliation of Adjusted EBITDAX, a non-GAAP measure, to net income (loss)). Adjusted EBITDAX increased by 30% sequentially.
Discretionary cash flow ("DCF"), defined as net cash provided by operating activities before changes in working capital, was $33.3 million for the quarter, compared to $22.0 million in the prior year period (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities). DCF increased by 24% sequentially.
NET INCOME
The Company announced a net loss applicable to common stock of $1.4 million for the quarter, or ($0.04) per basic share, versus a net loss applicable to common stock of $23.1 million, or ($0.64) per basic share in the prior year period.
PRODUCTION
Net production volumes in the quarter increased by 23% to 10.3 billion cubic feet equivalent ("Bcfe"), or an average of 113,300 Mcfe per day, versus 8.4 Bcfe, or an average of 92,000 Mcfe per day in the prior year period. Average net daily production volumes for the quarter were up 12% sequentially from the first quarter of 2011. Oil production averaged approximately 1,500 barrels of oil per day for the quarter.
Production for the third quarter of 2011 is expected to average 115,000 – 118,000 Mcfe per day, with oil production expected to comprise approximately 12 – 15% of total equivalent volumes.
REVENUES
Revenues for the quarter were $52.9 million versus $34.2 million in the prior year period. Revenues, including realized gain on derivatives not designated as hedges of $6.0 million for the quarter, would have been $58.9 million. Average realized price per unit for the quarter, prior to factoring in the Company's realized derivative gain, was $5.09 per Mcfe, versus $4.07 per Mcfe in the prior year period. When factoring in the Company's realized derivative gain, the average realized price per unit was $5.67 per Mcfe, versus $4.98 in the prior year period.
OPERATING EXPENSES
Per unit operating expenses for the quarter decreased by 12% compared to the prior year period and increased by 3% sequentially, as follows:
Lease operating expense ("LOE") on a unit basis decreased by 33% to $5.2 million in the quarter, or $0.51 per Mcfe, versus $6.3 million, or $0.76 per Mcfe in the prior year period. Per unit LOE for the quarter decreased by 6% sequentially. Lower per unit LOE continued to be driven by the Company's Haynesville Shale wells, which comprised 66% of the Company's volumes and averaged $0.18 per Mcfe for the quarter. The Company continues to expect LOE per unit to average $0.55 – 0.70 per Mcfe for 2011.
Production and other taxes for the quarter increased on a unit basis by 220% to $1.6 million, or $0.16 per Mcfe, versus $0.4 million, or $0.05 per Mcfe in the prior year period. Production and other taxes increased by 60% sequentially on a unit basis. The increase was driven by higher oil production, which carries a higher severance tax rate on a volume equivalent basis, and lower high cost credits for the quarter.
Transportation expense on a unit basis decreased by 15% to $2.3 million, or $0.22 per Mcfe, in the quarter, versus $2.2 million, or $0.26 per Mcfe in the prior year period. Transportation expense on a unit basis decreased by 15% sequentially.
Depreciation, depletion and amortization ("DD&A") expense on a unit basis decreased by 12% to $30.9 million, or $3.00 per Mcfe, for the quarter versus $28.4 million, or $3.39 per Mcfe, in the prior year period. DD&A expense for the quarter on a unit basis increased by 9% sequentially due to higher production volumes coming from the Company's Eagle Ford Shale oil trend, which carries a higher DD&A rate on a volume equivalent basis.
Exploration expense on a unit basis decreased by 26% to $2.3 million, or $0.23 per Mcfe for the quarter, versus $2.6 million, or $0.31 per Mcfe, in the prior year period. Exploration expense for the quarter on a unit basis decreased by 15% sequentially. Approximately $1.4 million ($0.13 per Mcfe), or 61% of exploration expense for the quarter was non-cash associated with amortization of the Company's undeveloped leasehold.
General and Administrative (G&A) expense on a unit basis decreased by 15% to $7.3 million, or $0.71 per Mcfe in the quarter, versus $7.0 million, or $0.84 per Mcfe in the prior year period. Per unit G&A decreased by 22% sequentially. Of the total G&A expense for the quarter, $1.3 million ($0.13 per Mcfe), or 18% of the total, was non-cash expense associated with stock based compensation.
OPERATING INCOME
Operating income, defined as revenues minus operating expenses, totaled $2.1 million for the quarter versus an operating loss of $12.8 million for the prior year period. When adding in realized gain on derivatives not qualifying as hedges of $6.0 million, adjusted operating income for the quarter is $8.1 million.
OTHER INCOME (EXPENSE)
Interest expense for the quarter was $13.0 million, or $1.26 per Mcfe, versus $9.2 million, or $1.10 per Mcfe in the prior year period. Non-cash interest expense associated with the Company's convertible notes comprised 28% of the total, or $3.6 million ($0.35 per Mcfe).
Gain (loss) on derivatives not designated as hedges for the quarter was $11.0 million, or $1.06 per Mcfe, versus a gain of $0.3 million, or $0.04 per Mcfe, in the prior year period. The derivative gain for the quarter is comprised of a realized gain of $6.0 million and an unrealized gain of $5.0 million.
LIQUIDITY
The Company ended the quarter with approximately $31.3 million in cash and cash equivalents and restricted cash, with $22.5 million drawn on its senior credit facility, under which the Company currently has a borrowing base of $225 million. The Company expects that the borrowing base will be increased when redetermined by the lenders under the senior credit facility in September of this year.
To further enhance the Company's liquidity, the Board has authorized management to evaluate and pursue several property monetization options, such as non-core asset sales and potential partnerships and joint ventures.
CAPITAL EXPENDITURES
Capital expenditures for the quarter were $110.3 million, of which $89.2 million was spent on drilling and completion costs, $15.6 million on acreage acquisitions, $4.2 million on facility costs and $1.3 million on other expenditures. For the quarter, the Company conducted drilling operations on 18 gross (10 net) wells, added 15 gross (7 net) wells to production and had 10 gross (5 net) wells waiting on completion at the end of the quarter. The Company added 4 gross (2.7 net) wells from the Eagle Ford Shale, with 5 gross (3.3 net) wells waiting on completion. The Company is increasing its 2011 capital expenditure budget to $315 million from $235 million, and now expects to drill 53 gross (35 net) wells for the year, up from 34 gross (26 net) wells previously budgeted. The Company has increased its production guidance for the year, and now expects to grow production by 15 – 25% year-over-year, up from 10 – 20% growth as previously announced.
HEDGING
The Company has hedged an additional 500 barrels of oil per day through 2012 at $101.50 per barrel, bringing the total hedged oil volumes for the second half of 2011 to 1,500 barrels per day at a blended average price of approximately $102.00.
OPERATIONAL UPDATE
Texas
Eagle Ford Shale, LaSalle and Frio Counties, Texas
The Company has completed its Burns Ranch 15H (67% WI) well, a 9,200 foot lateral with 32 frac stages, at a 24-hour initial production rate of 1,250 barrels oil equivalent ("BOE") per day, comprised of 1,155 barrels of oil and 570 Mcf per day. The Burns Ranch 15H, which is the longest Eagle Ford Shale well drilled by the Company to date, has been online approximately 50 days and has averaged approximately 850 BOE (87% oil) per day.
The Company has completed its Burns Ranch 17H (67% WI) well, a 4,700 foot lateral with 19 frac stages, at a 24-hour initial production rate of 1,155 BOE per day, comprised of 1,108 barrels of oil and 280 Mcf per day.
The Company has completed its Burns Ranch 18H (67% WI) well, a 5,000 foot lateral with 19 frac stages, at a 24-hour initial production rate of 1,030 BOE per day, comprised of 955 barrels of oil and 450 Mcf per day.
The Company has completed its third Buda Lime well, the Carnes 6H (67% WI) well, an unstimulated 3,100 foot lateral, at a 24-hour initial production rate of 1,635 BOE per day, comprised of 1,380 barrels of oil and 1,535 Mcf per day. The well averaged 1,000 BOE per day over the first thirty days, and had an estimated completed well cost of less than $3.0 million.
The Company is currently flowing back its Burns Ranch 19H (67% WI) well, a 6,000 foot lateral, Burns Ranch 3H (67% WI), a 5,300 foot lateral, and Burns Ranch 20H (67% WI), a 5,900 foot lateral. The Company has drilled and is waiting on completion on its Burns Ranch 2H (67% WI), which has an 8,200 foot lateral, Burns Ranch 30H (67% WI), which has a 5,100 foot lateral and Burns Ranch 35H (67% WI), with a 9,400 foot lateral.
The Company has two rigs running full time drilling Eagle Ford Shale and Buda Lime wells. For the remainder of 2011, the Company currently anticipates drilling 5 gross (3.5 net) Eagle Ford Shale wells on the southern half and 8 gross (5.5 net) Buda Lime wells on the northern half of the Company's approximate 40,000 net acre block.
Angelina River Trend, Nacogdoches and Angelina Counties, Texas
The Nelson 1H (100% WI) well, which was previously released with an initial production rate of 12,400 Mcfe per day on a restricted choke, has averaged 9,800 Mcfe per day over 145 days and is currently producing at a rate of approximately 9,200 Mcfe per day, which significantly exceeds the Company's expected restricted choke type curve.
Cotton Valley Taylor Sand, South Henderson Field, Rusk County, Texas
The Company has completed its third Cotton Valley Taylor sand horizontal well in the field, the Craig 4H (100% WI), at an initial 24-hour production rate of 9,360 Mcfe per day, comprised of 8,400 Mcf per day and 160 barrels of oil per day. The Company is currently in completion phase on its Travis Crow – Holland 1H (100% WI) and Rayford – Siler 1H (100% WI) wells.
Tuscaloosa Marine Shale, Louisiana and Mississippi
The Company has increased its investment in the Tuscaloosa Marine Shale trend, and now owns approximately 79,000 net acres in the play at an average purchase price of $175 per acre. The Company anticipates commencement of exploration and development operations on the acreage in 2012.
OTHER INFORMATION
In this press release, the Company refers to two non-GAAP financial measures, Adjusted 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. Non-GAAP financial measures should be reviewed in addition to, and not as an alternative for the Company's reported results prepared in accordance to 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. References to prior year periods in this release refer to the comparable quarterly period of the prior calendar year.
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 AND PRODUCTION DATA | ||||||||||
(In Thousands, Except Per Share Amounts) | ||||||||||
Three Months Ended | Six Months Ended | |||||||||
June 30, | June 30, | |||||||||
2011 | 2010 | 2011 | 2010 | |||||||
Volumes | ||||||||||
Natural gas (Mcf) | 9,501 | 8,187 | 18,094 | 15,967 | ||||||
Oil liquids (Bbls) | 134 | 31 | 215 | 64 | ||||||
Mcfe - Total | 10,307 | 8,373 | 19,382 | 16,351 | ||||||
Mcfe per day | 113,268 | 92,015 | 107,085 | 90,340 | ||||||
Total Revenues | $ 52,871 | $ 34,162 | $ 94,102 | $ 74,617 | ||||||
Operating Expenses | ||||||||||
Lease operating expense | 5,215 | 6,329 | 10,118 | 13,561 | ||||||
Production and other taxes | 1,645 | 390 | 2,595 | 1,353 | ||||||
Transportation | 2,301 | 2,189 | 4,687 | 4,642 | ||||||
Depreciation, depletion and amortization | 30,927 | 28,403 | 55,886 | 58,616 | ||||||
Exploration | 2,325 | 2,627 | 4,741 | 5,606 | ||||||
Impairment | 1,050 | - | 1,050 | - | ||||||
General and administrative | 7,328 | 7,001 | 15,578 | 16,447 | ||||||
Gain on sale of assets | - | - | (236) | - | ||||||
Other | - | - | - | 8,500 | ||||||
Operating income (loss) | 2,080 | (12,777) | (317) | (34,108) | ||||||
Other income (expense) | ||||||||||
Interest expense | (12,965) | (9,195) | (23,793) | (18,315) | ||||||
Interest income and other | 10 | 53 | 22 | 106 | ||||||
Gain on derivatives not designated as hedges | 10,954 | 320 | 944 | 35,049 | ||||||
Gain from extinguishment of debt | 3 | - | 58 | - | ||||||
(1,998) | (8,822) | (22,769) | 16,840 | |||||||
Income (loss) before income taxes | 82 | (21,599) | (23,086) | (17,268) | ||||||
Income tax benefit (expense) | - | - | - | - | ||||||
Net income (loss) | 82 | (21,599) | (23,086) | (17,268) | ||||||
Preferred stock dividends | 1,512 | 1,512 | 3,024 | 3,024 | ||||||
Net loss applicable to common stock | $ (1,430) | $ (23,111) | $ (26,110) | $ (20,292) | ||||||
Unrealized gain (loss) on derivatives not designated as hedges | 4,990 | (6,815) | (12,168) | 26,829 | ||||||
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 - 3-D seismic | (634) | (440) | (634) | (880) | ||||||
Gain on sale of assets | - | - | 236 | - | ||||||
Gain on extinguishment of debt | 3 | - | 58 | - | ||||||
Impairment | (1,050) | - | (1,050) | - | ||||||
Adjusted net loss applicable to common stock (1) | $ (4,739) | $ (15,856) | $ (12,552) | $ (35,999) | ||||||
Discretionary cash flow (see non-GAAP reconciliation) (2) | $ 33,311 | $ 21,960 | $ 60,081 | $ 32,198 | ||||||
Adjusted EBITDAX (see calculation and non-GAAP reconciliation)( 3) | $ 43,685 | $ 26,868 | $ 77,413 | $ 50,823 | ||||||
Weighted average common shares outstanding - basic | 36,110 | 35,918 | 36,093 | 35,888 | ||||||
Weighted average common shares outstanding - diluted (4) | 36,110 | 35,918 | 36,093 | 35,888 | ||||||
Earnings per share | ||||||||||
Net loss applicable to common stock - basic | $ (0.04) | $ (0.64) | $ (0.72) | $ (0.57) | ||||||
Net loss applicable to common stock - diluted | $ (0.04) | $ (0.64) | $ (0.72) | $ (0.57) | ||||||
Adjusted earnings per share | ||||||||||
Adjusted net loss applicable to common stock - basic (1) | $ (0.13) | $ (0.44) | $ (0.35) | $ (1.00) | ||||||
Adjusted net loss applicable to common stock - diluted (1) | $ (0.13) | $ (0.44) | $ (0.35) | $ (1.00) | ||||||
(1) Adjusted net income (loss) applicable to common stock is defined as net income (loss) applicable to common stock adjusted to exclude certain charges or amounts in order to provide users of this financial information with additional meaningful comparisons between current results and the results of prior periods. Management presents this measure because (i) it is consistent with the manner in which the company's performance is measured relative to the performance of its peers, (ii) this measure is more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP. | |
(2) Discretionary cash flow is defined as net cash provided by operating activities before changes in operating assets and liabilities. Management believes that the non-GAAP measure of operating cash flow is useful as an indicator of an oil and gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Operating cash flow should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP. | |
(3) Adjusted EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives. Other excluded items include Interest income and other, Gain (loss) on sale of assets, Gain on early extinguishment of debt and Other expense | |
(4) Diluted shares excludes 11.3 million potentially dilutive instruments that were anti-dilutive due to the net loss applicable to common stock for the year to date period ended June 30, 2011. We report our financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods. | |
GOODRICH PETROLEUM CORPORATION | |||||||||||
Per Unit Sales Prices and Costs | |||||||||||
Three Months Ended | Six Months Ended | ||||||||||
June 30, | June 30, | ||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||
Average sales price per unit: | |||||||||||
Oil (per Bbl) | |||||||||||
Including realized gain on oil derivatives | $ 97.26 | $ 73.21 | * | $ 96.71 | $ 74.66 | * | |||||
Excluding realized gain on oil derivatives | $ 97.36 | $ 73.21 | $ 94.85 | $ 74.66 | |||||||
Natural gas (per Mcf) | |||||||||||
Including realized gain on natural gas derivatives | $ 4.77 | $ 4.82 | $ 4.74 | $ 4.95 | |||||||
Excluding realized gain on natural gas derivatives | $ 4.14 | $ 3.88 | $ 4.03 | $ 4.36 | |||||||
Natural gas and oil (per Mcfe) | |||||||||||
Including realized gain on oil and natural gas derivatives | $ 5.67 | $ 4.98 | $ 5.49 | $ 5.13 | |||||||
Excluding realized gain on oil and natural gas derivatives | $ 5.09 | $ 4.07 | $ 4.82 | $ 4.55 | |||||||
* | No oil derivatives in the periods presented in 2010. | ||||||||||
Costs Per Mcfe | |||||||||||
Lease operating expense | $ 0.51 | $ 0.76 | $ 0.52 | $ 0.83 | |||||||
Production and other taxes | $ 0.16 | $ 0.05 | $ 0.13 | $ 0.08 | |||||||
Transportation | $ 0.22 | $ 0.26 | $ 0.24 | $ 0.28 | |||||||
Depreciation, depletion and amortization | $ 3.00 | $ 3.39 | $ 2.88 | $ 3.58 | |||||||
Exploration | $ 0.23 | $ 0.31 | $ 0.24 | $ 0.34 | |||||||
Impairment | $ 0.10 | $ - | $ 0.05 | $ - | |||||||
General and administrative | $ 0.71 | $ 0.84 | $ 0.80 | $ 1.01 | |||||||
Gain on sale of assets | $ - | $ - | $ (0.01) | $ - | |||||||
Other | $ - | $ - | $ - | $ 0.52 | |||||||
$ 4.93 | $ 5.61 | $ 4.87 | $ 6.65 | ||||||||
Note: Amounts on a per Mcfe basis may not total due to rounding. | |||||||||||
GOODRICH PETROLEUM CORPORATION | |||||||||
Selected Cash Flow Data (In Thousands): | |||||||||
Reconciliation of Discretionary Cash Flow and Net Cash Provided by Operating Activities (unaudited) | |||||||||
Three Months Ended | Six Months Ended | ||||||||
June 30, | June 30, | ||||||||
2011 | 2010 | 2011 | 2010 | ||||||
Net cash provided by operating activities (GAAP) | $ 32,297 | $ 28,886 | $ 67,921 | $ 47,653 | |||||
Net changes in working capital | (1,014) | 6,926 | 7,840 | 15,455 | |||||
Discretionary cash flow | $ 33,311 | $ 21,960 | $ 60,081 | $ 32,198 | |||||
Supplemental Balance Sheet Data | |||||||||
As of | |||||||||
June 30, | December 31, | ||||||||
2011 | 2010 | ||||||||
(Unaudited) | |||||||||
Cash and cash equivalents | $ 547 | $ 17,788 | |||||||
Current portion of debt | 26,022 | 167,086 | |||||||
Long-term debt | 481,060 | 179,171 | |||||||
$ 507,082 | $ 346,257 | ||||||||
Reconciliation of Net income (loss) to Adjusted EBITDAX | |||||||||
Three Months Ended | Six Months Ended | ||||||||
June 30, | June 30, | ||||||||
2011 | 2010 | 2011 | 2010 | ||||||
Net Income (loss) (GAAP) | $ 82 | $ (21,599) | $ (23,086) | $ (17,268) | |||||
Exploration expense | 2,325 | 2,627 | 4,741 | 5,606 | |||||
Depreciation, depletion and amortization | 30,927 | 28,403 | 55,886 | 58,616 | |||||
Impairment | 1,050 | - | 1,050 | - | |||||
Stock compensation expense | 1,339 | 1,480 | 3,177 | 3,989 | |||||
Interest expense | 12,965 | 9,195 | 23,793 | 18,315 | |||||
Unrealized (gain) loss on derivatives not designated as hedges | (4,990) | 6,815 | 12,168 | (26,829) | |||||
Other excluded items * | (13) | (53) | (316) | 8,394 | |||||
Adjusted EBITDAX | $ 43,685 | $ 26,868 | $ 77,413 | $ 50,823 | |||||
* Other excluded items include Interest income and other, Gain (loss) on sale of assets, Gain on early extinguishment of debt and Other expense | |||||||||
Other Information | |||||||||
Three Months Ended | Six Months Ended | ||||||||
June 30, | June 30, | ||||||||
2011 | 2010 | 2011 | 2010 | ||||||
Interest expense - cash | $ 9,410 | $ 4,449 | $ 15,590 | $ 8,820 | |||||
Interest expense - noncash | 3,555 | 4,746 | 8,203 | 9,495 | |||||
Total Interest | 12,965 | 9,195 | 23,793 | 18,315 | |||||
Unrealized (gain) loss on derivatives not designated as hedges | (4,990) | 6,815 | 12,168 | (26,829) | |||||
Realized (gain) loss on derivatives not designated as hedges | (5,964) | (7,135) | (13,112) | (8,220) | |||||
Total (gain) loss on derivatives not designated as hedges | (10,954) | (320) | (944) | (35,049) | |||||
General and Administrative expense - cash | 5,989 | 5,521 | 12,401 | 12,458 | |||||
General and Administrative expense - noncash | 1,339 | 1,480 | 3,177 | 3,989 | |||||
Total General and Administrative expense | 7,328 | 7,001 | 15,578 | 16,447 | |||||
CONTACT: Robert Turnham, President, or Jan Schott, Chief Financial Officer, both of Goodrich Petroleum Corporation, +1-713-780-9494