Exhibit 99.1
NEWS from
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 SECOND QUARTER
FINANCIAL RESULTS AND OPERATIONAL UPDATE
• | Revenues more than double compared to second quarter of 2005 |
• | Company production volumes grow by over 100% compared to second quarter of 2005 and 20% sequentially over first quarter of 2006 |
• | Net volumes in Cotton Valley trend grow by approximately 50% sequentially from the first quarter of 2006 |
• | The Company conducted drilling operations on 30 Cotton Valley trend wells during the second quarter, increasing the number of total wells currently drilled to 128 with a 100% success rate |
Houston, Texas – August 7, 2006. Goodrich Petroleum Corporation today announced its financial and operating results for the second quarter ended June 30, 2006.
REVENUES
Total revenues for the second quarter of 2006 increased by 126% to $30.6 million, versus $13.6 million for the second quarter of 2005, primarily due to a 103% increase in natural gas and crude oil production and a 55% increase in the average net oil price to $58.04 per barrel of oil.
OPERATING INCOME
Operating income, defined as revenues minus operating expenses, was approximately $2.2 million for the second quarter of 2006, compared to $0.1 million in the second quarter of 2005.
NET INCOME
Net income for the second quarter of 2006 was $4.3 million versus a $0.4 million net loss for the second quarter of 2005. Net income applicable to common stock for the second quarter of 2006 was $2.8 million, or $0.11 per basic share, compared to a net loss applicable to common stock for the second quarter of 2005 of $0.6 million, or $0.03 per basic share.
CASH FLOW
Earnings before interest, taxes, DD&A and exploration (“EBITDAX”) for the second quarter of 2006 increased by 126% to $19.1 million, compared to $8.4 million in the second quarter of 2005 (see accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities).
Discretionary cash flow, defined as net cash provided by operating activities before changes in working capital, increased by 131% to $17.1 million for the second quarter of 2006, compared to $7.4 million in the second quarter of 2005 (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities).
PRODUCTION
Net production volumes in the second quarter of 2006 increased by more than 100% to approximately 4.0 billion cubic feet equivalent (“Bcfe”) or 43,700 thousand cubic feet equivalent (“Mcfe”) per day, compared to second quarter 2005 volumes of 2.0 Bcfe or 21,600 Mcfe per day, and increased by approximately 20%, on a sequential basis, from the first quarter of 2006. Eighty three percent of the Company’s production for the second quarter of 2006 was natural gas. All of the Company’s production volume increases were achieved from organic drillbit growth in the Cotton Valley trend.
Approximately 75% of net production volumes for the second quarter of 2006 came from Cotton Valley trend wells, versus approximately 36% of net production volumes in the second quarter of 2005 and 60% in the first quarter of 2006. The Company’s net Cotton Valley trend volumes increased by approximately 50% sequentially, to 32,800 Mcfe per day versus approximately 22,000 Mcfe per day in the first quarter. The Company has added approximately 25,000 Mcfe per day of net Cotton Valley production volumes from the year ago period. The Company’s net Cotton Valley trend volumes of 32,800 Mcfe per day produced from an average 86 net wells, or approximately 380 net Mcfe per day, per well. Gross Cotton Valley trend volumes increased by 40% sequentially over the first quarter of 2006, to approximately 49,000 Mcfe per day, from an average of 96 gross wells producing for the quarter, or approximately 500 gross Mcfe per day, per well.
OPERATING EXPENSES
Lease operating expense (“LOE”) for the quarter was $4.7 million, or $1.18 per Mcfe of production, versus $2.3 million, or $1.17 per Mcfe for the second quarter of 2005. The primary reason for the increase in LOE for the second quarter of 2006 was due to expenses in our South Louisiana operations, including uninsured losses associated with hurricane damage expenditures and P&A costs for several older non-operated wells. The impact of these items increased LOE by $0.17 per Mcfe. Cotton Valley LOE for the quarter was approximately $0.65 per Mcfe.
Depreciation, depletion and amortization (“DD&A”) expense for the second quarter of 2006 was $13.1 million, or $3.29 per Mcfe, versus $5.7 million, or $2.93 per Mcfe in the second quarter of 2005. The increase in DD&A per Mcfe was primarily due to higher production volumes coming from fields with higher DD&A rates. General and administrative (“G&A”) expense for the second quarter of 2006 was $4.2 million, or $1.06 per Mcfe, versus $1.8 million, or $0.92 per Mcfe in the second quarter of 2005. The increase in G&A was primarily due to the hiring of additional employees and expensing of certain stock based compensation. Of the $4.2 million of G&A for the quarter, $1.4 million, or $0.35 per Mcfe, was related to non cash stock based compensation, of which $0.9 million was associated with option expenses, which were not required to be expensed prior to 2006.
CAPITAL EXPENDITURES
Capital expenditures for the second quarter of 2006 totaled $80.3 million compared to $37.4 million in the second quarter of 2005. Of the $80.3 million, $63.8 million was incurred on the drilling and completion of Cotton Valley trend wells, $10.2 million was incurred on South Louisiana wells and facilities, $4.4 million was incurred on leasehold acquisitions of 13,000 net acres in the Cotton Valley trend and $1.9 million was incurred on other facilities.
During the first six months of 2006, the Company conducted drilling operations on approximately 50 gross wells in the Cotton valley trend and five wells in the South Louisiana transition zone. During the second quarter, the Company had 31 gross wells drilling (30 in the Cotton Valley Trend), with approximately 87% of the capital expenditures in the quarter associated with activities in the Cotton Valley trend. The Company funded its capital expenditures in the second quarter of 2006 through a combination of cash flow from operations, available cash and increased borrowings.
HEDGING
The Company reported a net gain on derivatives not qualifying for hedge accounting of $5.9 million ($3.8 million net of tax) for the second quarter of 2006, comprised of an unrealized gain of $5.4 million on its ineffective oil and gas hedges, a realized gain of approximately $0.2 million on its ineffective natural gas hedges and a $0.3 million unrealized gain related to interest rate swaps that did not qualify for hedge accounting treatment.
OPERATIONAL UPDATE
Cotton Valley Trend
Through July 31, 2006 the Company has drilled and logged 128 wells (116 wells through the second quarter) in the Cotton Valley trend with a 100% success rate, with 119 currently producing and 9 waiting on completion.
The 128 wells were drilled and logged at the following fields:
• | Dirgin Beckville - 48 |
• | North Minden - 55 |
• | Bethany Longstreet - 10 |
• | South Henderson - 6 |
• | Cotton South - 6 |
• | Blocker - 2 |
• | Cotton - 1 |
The Company has added approximately 13,000 net acres in the trend since the first quarter, at an all-in cost of approximately $340 per net acre, bringing the total to approximately 142,000 gross (94,000 net) acres.
In June 2006, the Company entered into an agreement with a third party covering the Company’s “deep rights” in approximately 20,500 acres on its Cotton Prospect in Nacogdoches County, Texas. The Company assigned 50% of its 40% interest in the deep rights, defined as the rights below the top of the Knowles Lime Formation at 12,901’ below the surface, while reserving 100% of its rights above that depth. In exchange for the assignment of 50% of its deep rights, the Company will receive $1.6 million and be carried on the drilling costs for its remaining 50% interest in a 16,500’ “Bossier Sand” test on the Cotton Prospect within 18 months from execution of the agreement. In the event the “Bossier Sand” test well is not drilled during the 18-month period, the Company will be entitled to a non-participation fee of $4.0 million. The initial payment of $1.6 million has been accounted for as a reduction in the Company’s cost basis for the Cotton Prospect.
South Louisiana
As previously announced, the Company drilled and logged its Gueymard No. 1 well, its initial test well at the St. Gabriel Field in Iberville and Ascension Parishes, which encountered approximately 60 feet of net pay. The well is awaiting final completion and preliminarily tested at a gross production rate of approximately 4,000 Mcf of gas per day and 200 barrels of oil per day, with 5,000 pounds of flowing tubing pressure. The Company owns a 70% working interest in the well.
In the Burrwood/West Delta 83 Field, the Company has drilled its Norton II well to total depth and logged over 60 feet of net oil and natural gas pay in the 10,500’ sand. The well is currently producing at a gross rate of approximately 1,700 Mcf per day and 85 barrels of oil per day. The Company owns a 65% working interest in the well.
In the Lafitte Field, the Company has drilled two successful wells during 2006 as previously announced. The Company owns a 49% working interest in the wells.
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 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 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 Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.
Goodrich Petroleum is an independent oil and gas exploration and production company listed on the New York Stock Exchange under the symbol “GDP”. The majority of its properties are in Louisiana and Texas.
GOODRICH PETROLEUM CORPORATION
SELECTED INCOME DATA
(In Thousands, Except Per Share Amounts)
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||
Total Revenues | $ | 30,626 | $ | 13,541 | $ | 55,877 | $ | 26,364 | ||||||||
Operating expenses | ||||||||||||||||
Lease operating expense | 4,670 | 2,288 | 8,254 | 4,532 | ||||||||||||
Production taxes | 1,631 | 971 | 3,215 | 1,757 | ||||||||||||
Transportation | 1,676 | 52 | 1,676 | 91 | ||||||||||||
Depletion, depreciation and amortization | 13,091 | 5,745 | 22,923 | 11,591 | ||||||||||||
Exploration | 1,870 | 2,418 | 3,364 | 3,942 | ||||||||||||
General and administrative | 4,195 | 1,805 | 7,966 | 3,425 | ||||||||||||
Gain on sale of assets | — | (18 | ) | — | (169 | ) | ||||||||||
Other | 1,259 | 176 | 1,259 | 400 | ||||||||||||
28,392 | 13,437 | 48,657 | 25,569 | |||||||||||||
Operating income | 2,234 | 104 | 7,220 | 795 | ||||||||||||
Other income (expense) | ||||||||||||||||
Interest expense | (1,502 | ) | (519 | ) | (2,197 | ) | (826 | ) | ||||||||
Gain (loss) on derivative instruments not qualifying for hedge accounting | 5,881 | (269 | ) | 19,423 | (10,112 | ) | ||||||||||
4,379 | (788 | ) | 17,226 | (10,938 | ) | |||||||||||
Income (loss) before income taxes | 6,613 | (684 | ) | 24,446 | (10,143 | ) | ||||||||||
Income tax (expense) benefit | (2,315 | ) | 239 | (8,556 | ) | 3,547 | ||||||||||
Net Income (loss) | 4,298 | (445 | ) | 15,890 | (6,596 | ) | ||||||||||
Preferred stock dividends | 1,512 | 158 | 2,993 | 316 | ||||||||||||
Preferred stock redemption premium | 9 | — | 1,545 | — | ||||||||||||
Net income (loss) applicable to common stock | $ | 2,777 | $ | (603 | ) | $ | 11,352 | $ | (6,912 | ) | ||||||
Net income (loss) per common share | ||||||||||||||||
Basic | $ | 0.17 | $ | (0.02 | ) | $ | 0.64 | $ | (0.30 | ) | ||||||
Diluted | $ | 0.17 | $ | (0.02 | ) | $ | 0.63 | $ | (0.30 | ) | ||||||
Net income (loss) applicable to common stock per common share | ||||||||||||||||
Basic | $ | 0.11 | $ | (0.03 | ) | $ | 0.46 | $ | (0.31 | ) | ||||||
Diluted | $ | 0.11 | $ | (0.03 | ) | $ | 0.45 | $ | (0.31 | ) | ||||||
Weighted average shares basic | 24,936 | 23,461 | 24,898 | 22,129 | ||||||||||||
Weighted average shares diluted | 25,446 | 23,461 | 25,406 | 22,129 | ||||||||||||
GOODRICH PETROLEUM CORPORATION
SELECTED FINANCIAL AND OPERATING DATA
(Unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||
Selected Cash Flow Data (In Thousands) | ||||||||||||||||
Reconciliation of EBITDAX to Net Cash | ||||||||||||||||
Provided by Operating Activities: | ||||||||||||||||
EBITDAX | $ | 19,096 | $ | 8,443 | $ | 33,821 | $ | 17,130 | ||||||||
Exploration | (1,870 | ) | (2,418 | ) | (3,364 | ) | (3,942 | ) | ||||||||
Prospect amortization | 1,326 | 657 | 2,484 | 1,199 | ||||||||||||
Gain on sale of assets | — | (18 | ) | — | (169 | ) | ||||||||||
Interest expense | (1,502 | ) | (519 | ) | (2,197 | ) | (826 | ) | ||||||||
Dry hole costs | 20 | 1,247 | 20 | 1,888 | ||||||||||||
Net changes in working capital | 12,161 | 12,217 | 24,240 | 14,509 | ||||||||||||
Net cash provided by operating activities | $ | 29,231 | $ | 19,609 | $ | 55,004 | $ | 29,789 | ||||||||
Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities: | ||||||||||||||||
Discretionary cash flow | $ | 17,070 | $ | 7,392 | $ | 30,764 | $ | 15,280 | ||||||||
Net changes in working capital | 12,161 | 12,217 | 24,240 | 14,509 | ||||||||||||
Net cash provided by operating activities (GAAP) | $ | 29,231 | $ | 19,609 | $ | 55,004 | $ | 29,789 | ||||||||
Selected Operating Data | ||||||||||||||||
Production | ||||||||||||||||
Natural gas (MMcf) | 3,295 | 1,194 | 5,915 | 2,520 | ||||||||||||
Oil and condensate (MBbls) | 113 | 128 | 224 | 226 | ||||||||||||
Total (Mmcfe) | 3,974 | 1,962 | 7,261 | 3,876 | ||||||||||||
Mcfe per day | 43,670 | 21,561 | 40,116 | 21,420 | ||||||||||||
Average sales price per unit: | ||||||||||||||||
Natural gas (per Mcf) | $ | 6.91 | $ | 7.14 | $ | 7.01 | $ | 6.77 | ||||||||
Oil (per Bbl) | 58.04 | 37.35 | 57.07 | 38.00 | ||||||||||||
Natural gas and oil (Mcfe) | 7.39 | 6.77 | 7.47 | 6.62 | ||||||||||||
Expenses per Mcfe | ||||||||||||||||
Lease operating expense | $ | 1.18 | $ | 1.17 | $ | 1.14 | $ | 1.17 | ||||||||
Production tax | 0.41 | 0.49 | 0.44 | 0.45 | ||||||||||||
DD&A | 3.29 | 2.93 | 3.16 | 2.99 | ||||||||||||
Exploration | 0.47 | 1.23 | 0.46 | 1.02 | ||||||||||||
General and Administrative | 1.06 | 0.92 | 1.10 | 0.88 |