Exhibit 99.1
NEWS from
![(GOODRICH PETROLEUM CORPORATION LOGO)](https://capedge.com/proxy/8-K/0000950134-08-019579/h64796h6479601.gif)
808 Travis, Suite 1320
Houston, Texas 77002
(713) 780-9494
Fax (713) 780-9254
![(GOODRICH PETROLEUM CORPORATION LOGO)](https://capedge.com/proxy/8-K/0000950134-08-019579/h64796h6479601.gif)
808 Travis, Suite 1320
Houston, Texas 77002
(713) 780-9494
Fax (713) 780-9254
Contact: | ||
Robert C. Turnham, Jr., President | Traded: NYSE (GDP) | |
David R. Looney, Chief Financial Officer |
FOR IMMEDIATE RELEASE
GOODRICH PETROLEUM ANNOUNCES
FINANCIAL AND OPERATIONAL RESULTS AND GUIDANCE
FINANCIAL AND OPERATIONAL RESULTS AND GUIDANCE
• | Record Net Income Applicable to Common Stock of $195 Million | ||
• | Company Exits the Quarter with $224 Million in Cash and Zero Outstanding Borrowings Under Bank Revolving Credit Facility. Net Debt to Cap Ratio of Approximately 4% | ||
• | Previously Announced Sale of Interest in Undeveloped Leasehold Generates Net Proceeds of $172 Million, Resulting in a Pre-Tax Book Gain of $146 Million | ||
• | Net Production Volumes Averaged 69,000 Mcfe Per Day for the Quarter, Representing 48% Growth Over the Prior Year Period | ||
• | Operating Income of $158 Million for the Quarter | ||
• | Cash Flow (EBITDAX) of $41 Million (Excludes Gain On Sale of $146 Million), Representing a 114% Increase from Prior Year Period | ||
• | Total Per Unit Operating Expenses Reduced by $0.73 Per Mcfe from Prior Year Period | ||
• | Preliminary Capital Expenditure Budget for 2009 Reduced by Approximately 15% to $300 Million. Production Volumes Expected to Grow in 2009 by 30 — 40% Over 2008 |
Houston, Texas — November 5, 2008. Goodrich Petroleum Corporation today announced its financial and operating results for the third quarter ended September 30, 2008.
Net Income applicable to common stockfor the quarter was $194.9 million versus a net loss applicable to common stock of $23.7 million for the third quarter of 2007. Net income applicable to common stock for the quarter was $5.50 per basic share ($4.68 per diluted share) compared to net loss applicable to common stock for the third quarter of 2007 of $0.94 per basic and diluted share. Net income for the quarter was positively impacted by a $146 million pre tax gain primarily on the sale of undeveloped leasehold rights associated with a portion of the Company’s deep rights in North Louisiana, which closed in July of this year, as well as an $83.5 million gain on derivatives not designated as hedges. Last year’s third quarter was negatively impacted by a non-cash adjustment of $14.8 million for an increase in the valuation allowance relative to the Company’s deferred tax asset, as required by SFAS No. 109 “Accounting for Income Taxes” (“SFAS 109”).
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Earnings before interest, taxes, DD&A and exploration (“EBITDAX”)for the quarter, increased by 114% to $41.1 million (excluding the $146 million gain on the sale of undeveloped leasehold rights) compared to $19.2 million in the third quarter of 2007 (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities). For purposes of calculating EBITDAX, we use earnings including realized gains (losses) from derivatives not qualifying for hedge accounting, but excluding unrealized gains (losses) from derivatives not qualifying for hedge accounting. Price realizations for natural gas during the current quarter equaled $9.14 per Mcf before the impact of settled derivative contracts, or approximately $0.08 above the average Henry Hub price, which is calculated on an MMbtu basis. When taking into account the impact of settled derivatives during the quarter, the realized price for natural gas was $8.88 per Mcf. For crude oil, the realized price during the quarter was $117.65 per barrel (the Company had no derivative contracts outstanding on crude oil during the quarter).
Discretionary cash flow (“DCF”), defined as net cash provided by operating activities before changes in working capital, increased to $26.0 million in the quarter (excluding the $146 million gain on the sale of undeveloped leasehold rights), up 51% from $17.2 million for the third quarter of 2007. It should be noted that while the gain on sale of certain deep rights in North Louisiana has been excluded from the calculation of DCF, the taxes provided for (due primarily to this sale) are only partially recovered in the DCF calculation. Specifically, the standard DCF calculation only adds back to cash flow the portion of the tax provision related to deferred taxes. In this case, however, there are approximately $12.7 million of current taxes, all of which are due to the previously mentioned sale transaction, which have had the impact of reducing DCF by $12.7 million. If one attempts to calculate a cash flow measure which completely excludes all impacts of the sale transaction, this $12.7 million should be added back to the above DCF number (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities).
Operating income (loss)(defined as revenues less lease operating expenses, production taxes, transportation, DD&A, exploration and general and administrative expenses), without including realized gains or losses on derivatives and income from discontinued operations, was a total of $158.0 million for the quarter, versus an operating loss of $8.5 million in the third quarter of 2007. It should be noted that Operating Income for the quarter includes the $146 million gain on sale of deep interests in North Louisiana. Excluding the gain on sale of deep rights, the Company would have had operating income of $12 million.
Gain (loss) on derivatives not designated as hedges.The Company had a gain on derivatives not designated as hedges for the quarter of $83.5 million, which includes a realized loss of $1.6 million and an $85.3 million unrealized gain on the Company’s portfolio of gas hedges, versus a gain of $2.4 million during the prior year’s quarter.
Income tax expensefor the quarter totaled $42.1 million versus $11.6 million in the third quarter of 2007. During the third quarter of 2008, as previously mentioned, the Company recognized a $146 million gain on the sale of undeveloped leasehold costs by virtue of its sale of certain deep interests in North Louisiana. As a result of the taxable income generated by this sale, in addition to the Company’s normal operations, it is now more likely than not that the Company will be in a position to utilize the majority of its net operating loss (“NOL”) carryforwards when filing its 2008 Federal income tax return. As such the Company is releasing an appropriate amount of the valuation allowance previously booked against the deferred tax assets resulting from the NOL carryforwards. The chart below details the components of the Company’s income tax provision for the nine months ended 9/30/2008 (in $000’s):
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Income before taxes | $ | 176,905 | ||
Estimated taxes using the 35% FIT rate | $ | 61,917 | ||
Estimated prorated state taxes due for FY 2008 | $ | 5,740 | ||
Impact of release of valuation allowance | ($25,528 | )1 | ||
Income tax expense | $ | 42,129 | ||
Income from continuing operations | $ | 134,776 | ||
Current Taxes | $ | 12,679 | ||
Deferred Taxes | $ | 29,450 |
1 | The amount of the valuation allowance released is approximately equal to the estimated Federal income tax rate of 35% multiplied by the amount of the NOL carryforwards estimated to be used or useable in the future, including the current fiscal year. |
LIQUIDITY AND LEVERAGE POSITION
The Company finished the quarter with $224 million in cash and cash equivalents and zero outstanding on its bank revolving credit facility. Based on current commodity prices, the Company’s existing natural gas hedges and expected production levels over the next twelve months (assuming no shut in production as a result of external issues such as hurricanes or infrastructure delays), the Company anticipates that it can accomplish the following :
1) | grow 2009 production volumes by approximately 30 — 40% over 2008 levels with a preliminary 2009 capital expenditure budget of $300 million, | ||
2) | fund the capital expenditure budget with cash flow from operations and available cash, and | ||
3) | exit 2009 with zero outstanding on its bank revolving credit facility. |
As a result of our strong liquidity position, the Company elected to maintain the Borrowing Base at the existing level of $175 million even though a majority of the bank group indicated that under their customary engineering, pricing and lending policies and practices in effect in October of 2008, GDP’s proved reserves would likely result in a Borrowing Base in excess of $200 million. Given expected growth in the Borrowing Base due to the Company’s ongoing development drilling program, the Company anticipates that the combination of unused borrowing availability and short term investments will approximate $275 to $300 million as the Company enters 2010.
As of September 30, 2008, the Company’s ratio of net debt to total capital (total outstanding debt, net of cash and cash equivalents divided by total outstanding debt, net of cash and cash equivalents, plus total stockholders equity) stood at 3.9%.
OPERATING EXPENSES
Lease operating expense (“LOE”)for the quarter was $8.2 million, or $1.29 per Mcfe, compared to $5.2 million, or $1.22 per Mcfe for the third quarter of 2007. LOE increased on a per unit basis by 6% per Mcfe from the third quarter of 2007, and by 57% in absolute terms over the prior year period. Per unit LOE was negatively impacted during the quarter by reduced volumes due to the majority of the Company’s production being shut-in during Hurricane Ike (approximately 300 MMcfe during the month of September). The absolute dollar increase was driven largely by an increase in the number of producing wells and the 48% increase in production, with the per unit increase due primarily to higher salt water disposal (“SWD”) and compressor costs on a per unit basis. As the Company still has additional SWD cost reduction projects in process at several major fields, we expect to see continued improvement in this expense category.
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Depreciation, depletion and amortization (“DD&A”) expense.The Company utilizes the successful efforts method of accounting, whereby the majority of DD&A expense is represented by capitalized drilling and completion costs divided by proved developed reserves only, based on the most recent reserve report prepared by the Company’s third party independent engineering firm. For the third quarter of 2008 the Company’s mid year reserve report resulted in a decrease in the per unit DD&A rate to $4.17 per Mcfe, which represented a $0.60 per Mcfe decrease from the $4.77 per Mcfe rate in the third quarter of last year, and a 13% decrease from the second quarter of 2008. On an absolute dollar basis, the DD&A expense of $26.4 million in the third quarter compared to $20.4 million recognized in the third quarter of 2007, with the increase due solely to the increased level of production.
General and administrative (“G&A”) expensedecreased by approximately 17% on a per unit basis from $1.18 per Mcfe in the third quarter of 2007 to $0.98 per Mcfe in the third quarter of 2008. The increase in total G&A expense from $5.1 million in the prior year period to $6.2 million in the current quarter was driven largely by an 18% increase in employee headcount over the same period. Stock based compensation, which is a non-cash item included in G&A, amounted to approximately 23% of total G&A, or $1.4 million in the current quarter, versus $1.6 million for the prior year period.
Production and other taxesfor the quarter were up slightly on a per unit basis from the prior year period, at $0.33 per Mcfe this quarter versus $0.30 in the prior year. Net production and other tax expense in the quarter was $2.1 million versus $1.3 million in the third quarter of 2007. Production and other taxes for the quarter consisted of $1.6 million of production taxes and $0.5 million of ad valorem taxes. Production taxes are net of $0.9 million of accrued tight gas sands credits for the Company’s wells in the state of Texas. During the third quarter of 2007, production and ad valorem taxes totaled $0.6 million and $0.7 million, respectively.
Exploration expenseper unit decreased by 20% to $0.33 per Mcfe during the quarter from $0.41 per Mcfe during the prior year period, due largely to the spreading of this primarily fixed cost category over a larger production base. The total dollar exploration expense increased from $1.8 million in the third quarter of 2007 to $2.1 million in the current quarter due primarily to an increase in non-cash undeveloped leasehold amortization, which increased from $1.5 million to $1.7 million over the period.
Impairment of oil and gas propertiesfor the quarter totaled $1.1 million based upon a re-evaluation of all of the Company’s properties upon receipt of the independent engineer’s mid-year report on reserves. All of the expense relates to two non-core fields located in Louisiana and Texas.
CAPITAL EXPENDITURES
Capital expendituresfor the quarter totaled $103.0 million compared to $81.3 million in the third quarter of 2007. Of the $103.0 million, $87.4 million was incurred on the drilling and completion of Cotton Valley Trend wells during the quarter, $13.3 million was incurred on leasehold acquisitions and $2.3 million was incurred on infrastructure and other costs. Although the Company conducted drilling and/or completion operations on 38 gross wells during the quarter, capital expenditures in excess of $0.25 million per well were recorded on over 70 wells during this period. The Company funded its capital expenditures in the quarter through a combination of cash flow from operations and available cash.
The Company has established a preliminary capital expenditure budget for 2009 of $300 million, down approximately 15% from the $350 million capital expenditure budget for 2008. Approximately 60% of the budget is currently estimated to be spent drilling Haynesville Shale horizontal wells, with the majority of the remaining 40% allocated to drilling James Lime horizontal wells, Cotton Valley Taylor sand horizontal
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wells and vertical Travis Peak wells. The Company expects to fund the 2009 capital expenditure budget from cash flow from operations and available cash, which is currently $224 million.
OPERATIONS
Productionfor the quarter from continuing operations was 6.3 Bcfe, or approximately 69,000 Mcfe per day, representing a 48% increase over the prior year period volumes of 4.3 Bcfe or 47,000 Mcfe per day. The Company completed 26 wells during the quarter (down from 35 wells completed in the second quarter of 2008), and production for the quarter was negatively impacted by Hurricane Ike, which caused the Company to shut in approximately 300 million cubic feet equivalent of cumulative production over an approximate ten day period. Natural gas comprised 96% of the Company’s production for the quarter. All of the Company’s production volume increases were achieved from organic drill bit growth in the Cotton Valley Trend. The Company anticipates production for the fourth quarter to average 72,000 to 75,000 Mcfe per day, or approximately 4% — 9% sequential growth over the third quarter. The Company’s fourth quarter guidance is impacted by delays resulting from (1) longer cycle times associated with the drilling of Haynesville Shale horizontal wells; (2) pipeline and infrastructure installation for the Company’s initial four discovery wells drilled on its Surprise prospect at Angelina River Trend; and (3) third party pipeline and gathering system maintenance in the Beckville and Minden areas, all of which will contribute to an estimated number of fourth quarter completions ranging from 18 to 22 wells. For 2009, the Company anticipates growing production volumes by 30 — 40% over average 2008 levels with its preliminary capital expenditure budget of $300 million.
Drilling operationscontinued at an aggressive pace in the Cotton Valley Trend, with the Company conducting drilling operations on 38 wells in the quarter. The Company completed and added to production 23 wells in five fields during the quarter, with an average gross initial production rate of approximately 2,500 Mcfe per day.
Year to date, the Company has completed 89 wells, with an average initial production rate of approximately 2,600 Mcfe per day, with 11 wells in completion stage but not producing on September 30, 2008. Field by field initial production rates for the wells completed in 2008 through the third quarter, are as follows:
Field | No. of Wells | Initial Production Rate | ||||
• Minden | 21 | 1,850 Mcfe/day | ||||
• Beckville | 5 | 1,900 Mcfe/day | ||||
• Bethany-Longstreet | 17 | 1,525 Mcfe/day | ||||
• South Henderson | 10 | 2,200 Mcfe/day | ||||
• Angelina River | 35 | 3,800 Mcfe/day | ||||
• Other | 1 | 2,000 Mcfe/day |
At September 30, 2008, the Company had 366 wells producing in the Cotton Valley Trend and 11 being completed, with a success rate with in the Trend of over 99%. At September 30, 2008 the Company had 389 wells that were drilled and logged at the following fields:
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Field | No. of Wells | |||
• Minden | 110 | |||
• Beckville | 73 | |||
• Bethany Longstreet | 50 | |||
• South Henderson | 33 | |||
• Angelina River Trend | 79 | |||
• Others | 44 |
Cotton Valley Trend acreage at September 30, 2008 was approximately 200,000 gross and 127,000 net acres.
BETHANY-LONGSTREET AND LONGWOOD FIELDS, CADDO AND DESOTO PARISHES, LOUISIANA
The Company has three non-operated rigs currently drilling horizontal Haynesville Shale wells on the Chesapeake joint venture acreage in the Bethany-Longstreet and Longwood fields. At Bethany-Longstreet, the Chesapeake — Holland 17H-1 (50% WI) was spud on September 22nd and the Chesapeake — Dorothy Branch 11H-1 (50% WI) was spud on October 29th. Both wells have an estimated length of lateral of approximately 4,000 feet. At Longwood, the Chesapeake — Percy Sharp 7H-1 (50% WI) was spud on October 18th, with an expected lateral of approximately 4,000 feet. The Company has also drilled its Lona Johnson 21-1 (50% WI), an additional vertical well at Longwood.
CADDO PINE ISLAND FIELD, CADDO PARISH, LOUISIANA
The Company has drilled and logged its Lanier 16-1 (50% WI) on the Matador joint venture acreage in the Caddo Pine Island field. The well encountered 287 feet of pay in the Haynesville Shale and is currently scheduled to be re-entered and drilled horizontally in the first quarter of 2009. The Company has two non-operated rigs currently running in the field. The Hall 5H-1 (50% WI), which was initially drilled as a vertical test, was re-entered and commenced horizontal drilling operations on October 15th. Results from the well are expected around the end of the year. The Company is also participating in the Ballco Farms 7 No. 1 (41% WI), the fifth vertical well drilled in the field, which spud on October 12th. It is anticipated that each of the five vertical wells drilled in the field to date will be re-entered and drilled horizontally in the fourth quarter of 2008 or first quarter of 2009.
BECKVILLE AND MINDEN FIELDS, PANOLA AND RUSK COUNTIES, TEXAS
The Company has drilled five vertical Haynesville Shale wells in the area, and expects to commence operations on its initial horizontal well, the Lutheran Church 5H-1 (100% WI) in November. The Company has commenced operations on its initial Cotton Valley Taylor sand horizontal well in Beckville, the GW Waldrop 3H -1 (100% WI), with an expected lateral of approximately 3,000 feet.
SOUTH HENDERSON, RUSK COUNTY, TEXAS
The Company drilled and completed its Robert Youngblood No. 8 (100% WI), a vertical Haynesville Lime well, with an initial production rate of 1,000 Mcfe per day. The Company has plans to drill a horizontal Haynesville Lime well in the field in 2009.
ANGELINA RIVER TREND, ANGELINA AND NACOGDOCHES COUNTIES, TEXAS
The Company completed three James Lime horizontal wells in the quarter. The USA LB 2H (57% WI) had an initial production rate of 12,900 Mcfe per day, the West Esparza 1H (57% WI) had an initial production rate of 5,300 Mcfe per day and the Bob Sessions 4H (100% WI) had an initial production rate of 4,400 Mcfe per day. The Company is currently drilling its Estes 4H-1 (100% WI), a horizontal James Lime well in the middle of its Cotton South prospect area.
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The Company has drilled and logged two discoveries on its Surprise prospect, the Grigsby No. 1 (50% WI) and Lilly No. 1 (50% WI). Both wells, which are awaiting completion, encountered pay in the James Lime and Travis Peak formations. The Company is currently drilling a third well, the Tucker No. 1 (50% WI) which will test the Haynesville Shale and the Hill No. 1 (50% WI), which is planned to test the James Lime and Travis Peak, and may be taken deeper to the Haynesville Shale. Completion of the first two wells is anticipated by the end of November, the Tucker No. 1 is scheduled to be completed in December and the Hill No. 1 in January. The Company owns a 50% interest in 6,000 acres in the prospect area. Total acreage in the Angelina River Trend is currently approximately 81,000 gross, 41,000 net acres.
Commenting on the quarter, Vice Chairman and CEO, Gil Goodrich, stated “The third quarter results of $195 million of net income illustrate the positive benefits of the actions taken during the quarter, the value of our assets and the benefits of our core strategy to hedge future production. Due to the proactive steps taken early in the third quarter, including our previously announced joint venture in the Haynesville Shale play and our follow on equity offering, we ended the quarter with approximately $224 million in cash and short term investments, no borrowings under our senior credit facility and a net debt to capital ratio of just under 4%. With approximately $400 million in available capital and liquidity, we believe we are uniquely positioned to adjust the amount and timing of our 2009 capital expenditure plans based on prevailing market conditions. While we hope and expect conditions to improve over the course of 2009, we believe current market conditions call for a cautious approach. As such, our board has approved a preliminary capital expenditure budget for next year which would reduce our investments by approximately 15% compared to 2008 to approximately $300 million. While this level of investment is designed to preserve cash, we are also extremely excited about the potential for the Haynesville Shale play and believe it will have a significant positive impact on both production and reserve growth in 2009. Our preliminary plan calls for approximately 60% of the budget to be earmarked for horizontal development of the Haynesville Shale and net production volumes to grow by approximately 30% to 40% over 2008. We are currently drilling four horizontal Haynesville wells in northwest Louisiana and while these longer cycle time wells may limit fourth quarter sequential production growth, we believe they will provide an excellent jump start on horizontal Haynesville activity and first quarter 2009 production. Our strong balance sheet and the wonderful mix within our project inventory provide us the opportunity to both emphasize Haynesville Shale development and fund our entire 2009 investments from anticipated cash flow and cash on hand and likely enter 2010 with cash remaining on the balance sheet and no borrowings under our senior credit facility.”
OTHER INFORMATION
In this press release, the Company refers to two non-GAAP financial measures, EBITDAX and discretionary cash flow, because of management’s belief that these measures are financial indicators of the Company’s ability to internally generate operating funds. Management also believes that these non-GAAP financial measures of operating income and cash flow are 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 gas exploration and production industry. EBITDAX and discretionary cash flow should not be considered as alternatives to operating income or 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, such as 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
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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 priorperiods, which may not be realized.
Goodrich Petroleum is an independent oil and gas exploration and production company listed on the New York Stock Exchange. The majority of its properties are in Louisiana and Texas.
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GOODRICH PETROLEUM CORPORATION
SELECTED INCOME DATA
(In Thousands, Except Per Share Amounts)
SELECTED INCOME DATA
(In Thousands, Except Per Share Amounts)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Total Revenues | $ | 60,376 | $ | 27,280 | $ | 171,902 | $ | 78,828 | ||||||||
Operating Expenses | ||||||||||||||||
Lease operating expense | 8,165 | $ | 5,215 | 22,931 | $ | 15,500 | ||||||||||
Production and other taxes | 2,110 | 1,292 | 5,699 | 996 | ||||||||||||
Transportation | 2,224 | 1,715 | 6,480 | 4,230 | ||||||||||||
Depreciation, depletion and amortization | 26,414 | 20,434 | 80,532 | 57,603 | ||||||||||||
Exploration | 2,062 | 1,754 | 5,841 | 5,847 | ||||||||||||
Impairment of oil and gas properties | 1,059 | 282 | 1,059 | 282 | ||||||||||||
General and administrative | 6,207 | 5,054 | 17,567 | 15,892 | ||||||||||||
Gain on sale of assets | (145,868 | ) | — | (145,868 | ) | — | ||||||||||
Operating income (loss) | 158,003 | (8,466 | ) | 177,661 | (21,522 | ) | ||||||||||
Other income (expense) | ||||||||||||||||
Interest expense | (3,886 | ) | (3,086 | ) | (12,059 | ) | (7,932 | ) | ||||||||
Interest income | 1,260 | — | 1,260 | — | ||||||||||||
Gain (Loss) on derivatives not designated as hedges | 83,477 | 2,378 | 10,043 | (3,475 | ) | |||||||||||
80,851 | (708 | ) | (756 | ) | (11,407 | ) | ||||||||||
Income (loss) from continuing operations before income taxes | 238,854 | (9,174 | ) | 176,905 | (32,929 | ) | ||||||||||
Income tax expense | (42,129 | ) | (11,641 | ) | (42,129 | ) | (3,379 | ) | ||||||||
Income (loss) from continuing operations | 196,725 | (20,815 | ) | 134,776 | (36,308 | ) | ||||||||||
Discontinued operations: | ||||||||||||||||
Gain (loss) on disposal, net of tax | (252 | ) | (928 | ) | 28 | 9,823 | ||||||||||
Income (loss) from discontinued operations, net of tax | (44 | ) | (401 | ) | 240 | 2,078 | ||||||||||
(296 | ) | (1,329 | ) | 268 | 11,901 | |||||||||||
Net income (loss) | 196,429 | (22,144 | ) | 135,044 | (24,407 | ) | ||||||||||
Preferred stock dividends | 1,512 | 1,511 | 4,535 | 4,535 | ||||||||||||
Net income (loss) applicable to common stock | $ | 194,917 | $ | (23,655 | ) | $ | 130,509 | $ | (28,942 | ) | ||||||
Income (loss) per common share from continuing operations | ||||||||||||||||
Basic | $ | 5.51 | $ | (0.83 | ) | $ | 3.93 | $ | (1.44 | ) | ||||||
Diluted | $ | 4.69 | $ | (0.83 | ) | $ | 3.47 | $ | (1.44 | ) | ||||||
Income (loss) per common share from discontinued operations | ||||||||||||||||
Basic | $ | (0.01 | ) | $ | (0.05 | ) | $ | 0.01 | $ | 0.47 | ||||||
Diluted | $ | (0.01 | ) | $ | (0.05 | ) | $ | 0.01 | $ | 0.47 | ||||||
Net income (loss) per common share applicable to common stock | ||||||||||||||||
Basic | $ | 5.50 | $ | (0.94 | ) | $ | 3.94 | $ | (1.15 | ) | ||||||
Diluted | $ | 4.68 | $ | (0.94 | ) | $ | 3.48 | $ | (1.15 | ) | ||||||
Weighted average common shares outstanding: | ||||||||||||||||
Basic | 35,440 | 25,204 | 33,098 | 25,177 | ||||||||||||
Diluted | 42,185 | 25,204 | 39,756 | 25,177 |
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GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data (In Thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Calculation of EBITDAX: | ||||||||||||||||
Revenue | 60,376 | 27,280 | 171,902 | 78,828 | ||||||||||||
Lease operating expense | (8,165 | ) | (5,215 | ) | (22,931 | ) | (15,500 | ) | ||||||||
Production and other taxes | (2,110 | ) | (1,292 | ) | (5,699 | ) | (996 | ) | ||||||||
Transportation | (2,224 | ) | (1,715 | ) | (6,480 | ) | (4,230 | ) | ||||||||
G&A — cash portion only | (4,904 | ) | (3,485 | ) | (13,557 | ) | (11,642 | ) | ||||||||
Realized gain (loss) on derivatives not designated as hedges | (1,854 | ) | 3,672 | (3,436 | ) | 8,499 | ||||||||||
EBITDAX | 41,119 | 19,245 | 119,799 | 54,959 | ||||||||||||
Reconciliation of EBITDAX to Net Cash Provided by Operating Activities: | ||||||||||||||||
EBITDAX | 41,119 | 19,245 | 119,799 | 54,959 | ||||||||||||
EBITDAX — Discontinued Operations | 85 | 302 | 369 | 5,746 | ||||||||||||
Exploration | (2,062 | ) | (1,754 | ) | (5,841 | ) | (5,847 | ) | ||||||||
Prospect amortization | 1,720 | 1,663 | 4,169 | 5,095 | ||||||||||||
Interest expense | (3,886 | ) | (3,086 | ) | (12,059 | ) | (7,932 | ) | ||||||||
Interest income | 1,260 | — | 1,260 | — | ||||||||||||
Current Income taxes | (12,679 | ) | — | (12,679 | ) | — | ||||||||||
Other non-cash items | 409 | 805 | 1,365 | 400 | ||||||||||||
Net changes in working capital | 15,159 | 4,497 | 1,838 | 9,167 | ||||||||||||
Net cash provided by operating activities (GAAP) | 41,125 | 21,672 | 98,221 | 61,588 | ||||||||||||
Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities: | ||||||||||||||||
Discretionary cash flow | 25,966 | 17,175 | 96,383 | 52,421 | ||||||||||||
Net changes in working capital | 15,159 | 4,497 | 1,838 | 9,167 | ||||||||||||
Net cash provided by operating activities (GAAP) | 41,125 | 21,672 | 98,221 | 61,588 |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Selected Operating Data: | ||||||||||||||||
Production — Continuing Operations: | ||||||||||||||||
Natural gas (MMcf) | 6,088 | 4,101 | 16,962 | 10,846 | ||||||||||||
Oil and condensate (MBbls) | 40 | 30 | 123 | 84 | ||||||||||||
Total (Mmcfe) | 6,328 | 4,281 | 17,700 | 11,350 | ||||||||||||
Average sales price per unit: | ||||||||||||||||
Natural gas (per Mcf) | $ | 9.14 | �� | $ | 6.09 | $ | 9.29 | $ | 6.73 | |||||||
Oil (per Bbl) | 117.65 | 73.32 | 112.28 | 64.12 | ||||||||||||
Natural gas and oil (per Mcfe) | 9.54 | 6.34 | 9.68 | 6.90 | ||||||||||||
Expenses per Mcfe: | ||||||||||||||||
Lease operating expense | $ | 1.29 | $ | 1.22 | $ | 1.30 | $ | 1.37 | ||||||||
Production and other taxes | 0.33 | 0.30 | 0.32 | 0.09 | ||||||||||||
Transportation | 0.35 | 0.40 | 0.37 | 0.37 | ||||||||||||
DD&A | 4.17 | 4.77 | 4.55 | 5.08 | ||||||||||||
Exploration | 0.33 | 0.41 | 0.33 | 0.52 | ||||||||||||
Impairment expense | 0.17 | 0.07 | 0.06 | 0.03 | ||||||||||||
General and administrative | 0.98 | 1.18 | 0.99 | 1.40 |
10