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 AND OPERATIONAL RESULTS
| | • | | Net Production Volumes Grow By Over 28% Compared To Second Quarter Of 2006 And 11% Sequentially Over First Quarter Of 2007 To 41,000 Mcfe Per Day |
| |
| | • | | Third Quarter Net Production Volumes Anticipated To Be In Excess Of 10% Sequential Growth Over Second Quarter |
| |
| | • | | Cash Flow (EBITDAX) Increases 40% Over the Second Quarter of 2006 |
| |
| | • | | Conducted Drilling Operations On 30 Cotton Valley Trend Wells During The Quarter, Increasing The Number Of Total Wells Drilled Through The Quarter To 203, With In Excess Of A 99% Success Rate |
| |
| | • | | Initial James Lime Horizontal Well Discovery at 6,900 Mcfe Per Day On Angelina River Trend Acreage Highlights Value of Acreage Position And Incremental Reserve Potential |
| |
| | • | | New Joint Venture on Cotton Valley Trend Acreage Adds Approximately 19,500 Gross, 6,400 Net Acres. Horizontal Well to be Drilled in 120 Days |
Houston, Texas — August 8, 2007. Goodrich Petroleum Corporation today announced its financial and operating results for the second quarter ended June 30, 2007.
Given the sale of most of the Company’s south Louisiana assets in the second quarter, the Company is required to use discontinued operations treatment for these assets. As such, all of the revenue and expense items specifically attributable to those assets have been captured in a separate line item on the attached Income Statement entitled “Discontinued operations” for both the current quarter and the quarter ended June 30, 2006. Additionally, the remaining minor properties owned by the Company in south Louisiana are currently being marketed for sale, and are included under the asset caption “Assets held for sale.” All remaining Income Statement items relate only to
those assets retained by the Company, virtually all of which are a part of the Company’s Cotton Valley Trend operations. Consistent with utilizing the discontinued operations methodology, the Company recorded a $10.8 million gain after tax on the sale of the assets in the first six months of the year, and another $2.5 million in after tax income from the discontinued operations during the six month period.
Net Income (loss)for the second quarter of 2007 was a loss of $3.3 million versus net income of $4.3 million for the second quarter of 2006. Net loss applicable to common stock for the second quarter of 2007 was $4.8 million, or ($0.19) per basic share, compared to net income applicable to common stock for the second quarter of 2006 of $2.8 million, or $0.11 per basic share.
Earnings before interest, taxes, DD&A and exploration (“EBITDAX”)for the second quarter of 2007 increased by 40% to $17.9 million, compared to $12.8 million in the second quarter of 2006 (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.
Discretionary cash flow (“DCF”), defined as net cash provided by operating activities before changes in working capital, totaled $15.4 million for the second quarter of 2007 (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities).
The Company had a gain on derivatives not qualifying for hedge accounting for the second quarter of 2007 of $3.6 million, due largely to an unrealized gain of $2.4 million on the change in the mark to market value of the Company’s portfolio of ineffective gas and oil hedges, coupled with a realized gain on the Company’s cash settlements on hedging contracts of $1.0 million for the quarter. During the second quarter of 2006 the Company recorded a gain on derivatives not qualifying for hedge accounting of $5.9 million before taxes.
Operating income (loss)(defined as revenues less lease operating expenses, production taxes, transportation, DD&A, exploration and general and administrative expenses), without including realized gain on derivatives and income from discontinued operations, was a loss of $5.7 million for the second quarter of 2007, versus an operating loss of $0.2 million in the second quarter of 2006.
The operating loss for the quarter was primarily a result of higher DD&A and lease operating expenses (“LOE”), both of which the Company expects to be lower for the remainder of the year due to revised DD&A rates from the mid-year reserve report and the implementation of several salt water disposal (“SWD”) cost reduction plans, including the completion of the low pressure gathering system in the Beckville Field of East Texas in late June.
OPERATING EXPENSES
Lease operating expense (“LOE”)for the quarter was $6.3 million, or $1.70 per Mcfe of production, versus $2.4 million, or $0.80 per Mcfe for the second quarter of 2006. The primary reasons for the increase in LOE for the second quarter of 2007 were (a) workover costs of $1.3 million in 2Q07 versus no workover costs in 2Q06, and (b) SWD expenses of $1.8 million in 2Q07 versus $0.9 million in 2Q06. The increase in SWD costs per Mcfe of production, from $0.30 in 2Q06 to $0.47 in 2Q07 is primarily a function of the longer distances required to truck water produced by the Company’s wells in several newer fields where existing SWD systems were
not in place. Beginning with the third quarter of 2007, the Company will have much improved SWD capabilities in the Beckville field, with new facilities expected to come on line in the Bethany Longstreet, Cotton South and Minden fields by the end of the year. As the Company is able to begin utilizing the previously disclosed low pressure gathering system (completed in late June, 2007) in the Beckville field, we expect to see meaningful decreases in operating expenses later this year, particularly as it relates to SWD costs.
Depreciation, depletion and amortization (“DD&A”) expensefor the second quarter of 2007 was $19.5 million, or $5.24 per Mcfe, versus $10.0 million, or $3.44 per Mcfe in the second quarter of 2006. The Company utilizes successful efforts accounting, with the increase in DD&A per Mcfe due primarily to higher production volumes coming from fields with higher DD&A rates, which were calculated using the Company’s proved developed reserves contained in its year end reserve report based on a $5.63 per Mcf gas price. A mid-year reserve report is being prepared using a gas price at June 30, 2007 of $6.79 per MMBtu, and will include the impact of the Company’s first half of 2007 drilling program. The Company intends to use the data from this report to re-calculate its DD&A rate beginning in the third quarter.
General and administrative (“G&A”) expensefor the second quarter of 2007 was $5.5 million, or $1.48 per Mcfe, versus $4.2 million, or $1.45 per Mcfe in the second quarter of 2006. The increase in G&A was primarily due to higher payroll expenses. Of total G&A costs, non-cash costs, primarily stock based compensation, totaled $1.3 million.
Production taxesfor the quarter were booked as a $0.8 million credit, or negative expense, due to the booking of severance tax rebates in the State of Texas for many of the Company’s Cotton Valley Trend wells. In the prior year period, production taxes were $0.9 million.
Exploration expensewas $1.8 million during the second quarter of 2007, or $0.48 per Mcfe, versus $1.5 million, or $0.52 per Mcfe in the prior year period. Non-cash leasehold amortization costs represented virtually all of the $1.8 million. All of the Company’s undeveloped Cotton Valley Trend acreage is amortized over a three year period as exploration expense.
CAPITAL EXPENDITURES
Capital expendituresfor the second quarter of 2007 totaled $59.9 million compared to $80.0 million in the second quarter of 2006. Of the $59.9 million, $55.0 million was incurred on the drilling and completion of Cotton Valley Trend wells during the quarter, $2.1 million was incurred on infrastructure and $2.8 million was incurred on leasehold acquisitions in the Cotton Valley Trend. Although the Company conducted drilling or completion operations on 30 gross wells drilling during the quarter, capital expenditures in excess of $0.25 million per well were accrued on over 38 wells during this period. The Company funded its capital expenditures in the second quarter of 2007 through a combination of cash flow from operations, draws under its bank revolver, and available cash.
OPERATIONS
Productionfor the quarter, excluding volumes from discontinued operations, was approximately 3.7 Bcfe or approximately 41,000 Mcfe per day, representing a 28% increase over second quarter 2006 volumes of 2.9 Bcfe or 32,000 Mcfe per day, and an approximate 11% increase over production volumes for the first quarter of 2007. Natural gas comprised 95% of the Company’s production for the quarter. All of the Company’s production volume increases were achieved from organic drillbit growth in the Cotton Valley Trend. The Company anticipates production for the third quarter to average 45,000 to 47,000 Mcfe per day, which would equate to a minimum 10.0% sequential growth over the second quarter. Current production rate is approximately 46,000 Mcfe per day.
Drilling operationscontinued at an aggressive pace in the Cotton Valley Trend, with the Company conducting drilling operations on 30 wells with an average of ten rigs (nine of which were operated) running full time in the quarter. The Company completed 20 wells in five fields during the quarter, with an average gross initial production rate of approximately 2,300 Mcfe per day, versus the historical average of 1,700 Mcfe per day.
In 2007 the Company initiated a highly focused vertical well drilling plan with a majority of its 2007 wells designated as in-fill development. In addition, the Company continued testing the viability of completing and stimulating wells using Contact Technology, or JITP, a “single stage, multi-layered fracture stimulation technology” during the second quarter of 2007. The Company utilized JITP on seven wells during the quarter, with an average gross initial production rate from those wells of 2,375 Mcf per day. The results to date have been positive versus the traditional completion of the offset wells. The Company has also begun testing 20 acre spaced wells, with continuing success. The latest well drilled and completed at reduced spacing, the KF Carter A2 well, averaged a gross 2,650 Mcf per day for the first 30 days versus 2,550 Mcf per day for the offset well, the JWGU B1 well. The Company continues to monitor results on 20 acre spacing and has three more wells planned on 20 acre spacing to be spud by the end of the year, including its first increased density well at Minden, the A. Brooks #5 well.
Year to date, the Company has completed 34 wells, with an average initial production rate of approximately 2,200 Mcfe per day, versus the historical average of 1,700 Mcfe per day, with ten wells in completion stage but not producing on June 30, 2007. Field by field initial production rates for the wells completed in 2007 through the second quarter, are as follows:
| | | | | | | | | | | |
| | | Field | | No. of Wells | |
| | Initial Production Rate |
| | | | | | | | | | | |
• | | Minden | | | 9 | | | | | 1,900 Mcfe/day |
• | | Dirgin-Beckville | | | 7 | | | | | 2,200 Mcfe/day |
• | | Bethany-Longstreet | | | 7 | | | | | 2,200 Mcfe/day |
• | | South Henderson | | | 5 | | | | | 1,900 Mcfe/day |
• | | Angelina River | | | 6 | | | | | 3,000 Mcfe/day |
The Angelina River total above does not include the recently announced James Lime horizontal completion that tested at 6,900 Mcfe/day.
At June 30, 2007, the Company had 193 wells producing in the Cotton Valley Trend and ten being completed, with an average 183 producing for the entire quarter at an average gross rate of approximately 375 Mcfe per day. The Company has drilled and logged 203 wells in the Cotton
Valley Trend with in excess of a 99% success rate. The 203 wells were drilled and logged at the following fields:
| | | | | | | | | | | |
| | | Field | | No. of Wells | |
| |
|
| | | | | | | | | | | |
• | | Minden | | | 73 | | | | | |
• | | Dirgin Beckville | | | 58 | | | | | |
• | | Bethany Longstreet | | | 22 | | | | | |
• | | South Henderson | | | 13 | | | | | |
• | | Angelina River Trend | | | 23 | | | | | |
• | | Others | | | 14 | | | | | |
Cotton Valley Trend acreagewas relatively steady during the quarter, with the total at June 30, 2007 being approximately 185,000 gross, 113,000 net acres. Since the end of the quarter, the Company has added approximately 19,500 gross, 6,400 net acres to inventory by virtue of the joint venture described below, which brings the current total to 204,500 gross, 119,400 net acres.
SPECIFIC FIELD UPDATES
Caddo Parish Joint Venture
Caddo Parish, Louisiana
The Company announced that it has entered into a joint venture to drill to earn a 67.5% working interest in approximately 19,500 gross acres, (resulting in the Company earning 6,400 net acres) in Caddo Parish, Louisiana, which is north of and on trend with the Company’s Bethany-Longstreet field in Caddo and DeSoto Parishes. The Company plans to drill its initial well within 120 days, which will be a horizontal Cotton Valley sand test targeting the same interval as seen in its Champe Graham 3-H horizontal well at Bethany-Longstreet.
Bethany-Longstreet Field
Caddo and DeSoto Parishes, Louisiana
The Company continued its aggressive development activities in the Bethany-Longstreet field of Northwest Louisiana in the quarter. The Company conducted drilling operations on five wells, including the Jimmy Holmes 1-H, the Company’s initial horizontal re-entry of an existing wellbore in the field. The well is currently approximately 600 feet into the horizontal lateral with a projected target of 2,000 feet of displacement. The drilling and completion of the well has been delayed due to slower than expected drilling and problems incurred while pulling the packer from the original completion. Upon completion of the Jimmy Holmes 1-H, which the Company expects to occur in September, the Company currently has plans to spud two additional horizontal wells in the Field by the end of the year on its 21,000 gross acres
The Champe Graham No. 3-H, the Company’s initial horizontal well in the field, has now been online and producing 120 days, with a current rate of 2,100 Mcf per day. The Company currently estimates 4.3 Bcfe of reserves for the well. Water production has
continued to drop, with an average 61 barrels of water per million cubic feet of gas produced over the last 30 days.
The Company is currently completing its WF Johnson #2 well, a dual completion in the Hosston and Cotton Valley Sands. Both zones are currently in the flowback stage, with the Hosston producing to sales at 1,800 Mcf/day on 28/64 inch choke with 700 psi and 55% of frac fluid recovered and the Cotton Valley at 400 Mcf per day, with 56% of the frac fluid recovered.
Angelina River Trend
Angelina and Nacogdoches Counties, Texas
The Company participated in drilling operations on eight wells in the Angelina River Trend during the quarter, and completed four, with an average initial production rate of 2,600 Mcf per day. The average initial production rate does not include the Middlebrook 1-H, which was completed in July.
Cotton Prospect
As previously reported, the Company has completed its initial horizontal James Lime well, the Middlebrook 1-H in the Angelina River Trend. The well tested at 6,900 Mcf per day on a 36/64 inch choke with 1350 psi. The well had a gross completed well cost of approximately $3 million. The Company owns a 40% working interest in the well and a blended average 50% interest in its acreage block of 69,500 acres. The Middlebrook 1-H was drilled with a 6,000 foot lateral and had six successful frac stages of the seven attempted. The Company currently estimates 160-200 acre drainage per well. The Company anticipates spudding its second horizontal James Lime well during the third quarter.
Cotton South Prospect
The Company participated in drilling operations on four wells and completed two wells in the Cotton South prospect during the quarter, with an average initial production rate of 2,900 Mcf per day.
Bethune Prospect
During the second quarter the Company drilled two additional wells on its Bethune prospect, the Beverly Sutton 1 and Bethune A-1 wells. The Beverly Sutton #1, which is the southeastern most well drilled to date on the Company’s Angelina River Trend acreage, is in flowback stage, with 73% of the frac fluid recovered and a gas rate of 2,450 Mcf per day with 2,375 psi. The Bethune A-1 well is waiting on completion.
Commenting on the quarter, Vice Chairman and CEO, Gil Goodrich, stated “We achieved significant operational objectives and successes during the second quarter. Not only did we achieve our internal production target for the quarter, we also made excellent progress on our strategy to exploit our numerous catalysts for growth. In the Bethany-Longstreet field we continued our positive production performance with the addition of
another prolific Hosston producer, as well as continued solid production performance from our initial Cotton Valley horizontal well in this field. Our Cotton Valley 20 acre spaced drilling program continues to deliver positive results, which we believe will continue to add to our inventory of potential locations and their corresponding reserves. Adding to our solid operational performance in the quarter was the stellar performance in the Angelina River Trend. Not only were we able to continue the successful development, exploitation and expansion of our proved Travis Peak reserves in this area, but the excellent results from our initial James Lime horizontal well has, we believe, added significant incremental value to our Angelina River Trend acreage. Financially, we are pleased to have successfully initiated operation of our low pressure gathering system and salt water transportation system in the Beckville area, which we believe will have the dual positive effects of enhancing natural gas production from the 55 wells currently in the system and significantly reducing lease operating expenses in the coming quarters. In addition, with the pending completion of our mid-year 2007 reserve report, we expect to report reduced DD&A expenses 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, 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 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. The majority of its properties are in Louisiana and Texas.
GOODRICH PETROLEUM CORPORATION
SELECTED UNAUDITED INCOME DATA
(In Thousands, Except Per Share Amounts)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| |
| Total Revenues | | $ | 28,006 | | | $ | 20,154 | | | $ | 51,548 | | | $ | 34,923 | |
| | | | | | | | | | | | | | | | | |
| Operating Expenses | | | | | | | | | | | | | | | | |
| Lease operating expense | | | 6,310 | | | | 2,326 | | | | 10,421 | | | | 4,564 | |
| Production taxes | | | (750 | ) | | | 901 | | | | (432 | ) | | | 1,803 | |
| Transportation | | | 1,440 | | | | 1,488 | | | | 2,515 | | | | 1,488 | |
| Depreciation, depletion and amortization | | | 19,461 | | | | 9,984 | | | | 37,169 | | | | 15,866 | |
| Exploration | | | 1,767 | | | | 1,508 | | | | 4,093 | | | | 2,907 | |
| General and administrative | | | 5,500 | | | | 4,195 | | | | 10,838 | | | | 7,966 | |
| | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | (5,722 | ) | | | (248 | ) | | | (13,056 | ) | | | 329 | |
| | | | | | | | | | | | | | | | | |
| Other income (expense) | | | | | | | | | | | | | | | | |
| Interest expense | | | (2,222 | ) | | | (1,502 | ) | | | (4,846 | ) | | | (2,197 | ) |
| Gain (loss) on derivatives not qualifying for hedge accounting | | | 3,634 | | | | 5,881 | | | | (5,853 | ) | | | 19,423 | |
| | | | 1,412 | | | | 4,379 | | | | (10,699 | ) | | | 17,226 | |
| | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations before income taxes | | | (4,310 | ) | | | 4,131 | | | | (23,755 | ) | | | 17,555 | |
| Income tax (expense) benefit | | | 1,519 | | | | (1,412 | ) | | | 8,262 | | | | (6,110 | ) |
| Income (loss) from continuing operations | | | (2,791 | ) | | | 2,719 | | | | (15,493 | ) | | | 11,445 | |
| | | | | | | | | | | | | | | | | |
| Discontinued operations: | | | | | | | | | | | | | | | | |
| Gain (loss) on disposal, net of tax | | | (162 | ) | | | — | | | | 10,751 | | | | — | |
| Income (loss) from discontinued operations, net of tax | | | (346 | ) | | | 1,579 | | | | 2,479 | | | | 4,445 | |
| | | | (508 | ) | | | 1,579 | | | | 13,230 | | | | 4,445 | |
| | | | | | | | | | | | | | | | | |
| Net income (loss) | | | (3,299 | ) | | | 4,298 | | | | (2,263 | ) | | | 15,890 | |
| Preferred stock dividends | | | 1,512 | | | | 1,512 | | | | 3,024 | | | | 2,993 | |
| Preferred stock redemption premium | | | — | | | | 9 | | | | — | | | | 1,545 | |
| | | | | | | | | | | | | | | | | |
| Net income (loss) applicable to common stock | | $ | (4,811 | ) | | $ | 2,777 | | | $ | (5,287 | ) | | $ | 11,352 | |
| | | | | | | | | | | | | | | | | |
| Income (loss) per common share from continuing operations | | | | | | | | | | | | | | | | |
| Basic | | $ | (0.11 | ) | | $ | 0.11 | | | $ | (0.62 | ) | | $ | 0.46 | |
| Diluted | | $ | (0.11 | ) | | $ | 0.11 | | | $ | (0.62 | ) | | $ | 0.45 | |
| | | | | | | | | | | | | | | | | |
| Income (loss) per common share from discontinued operations | | | | | | | | | | | | | | | | |
| Basic | | $ | (0.02 | ) | | $ | 0.06 | | | $ | 0.53 | | | $ | 0.18 | |
| Diluted | | $ | (0.02 | ) | | $ | 0.06 | | | $ | 0.52 | | | $ | 0.17 | |
| | | | | | | | | | | | | | | | | |
| Net income (loss) per common share applicable to common stock | | | | | | | | | | | | | | | | |
| Basic | | $ | (0.19 | ) | | $ | 0.11 | | | $ | (0.21 | ) | | $ | 0.46 | |
| Diluted | | $ | (0.19 | ) | | $ | 0.11 | | | $ | (0.21 | ) | | $ | 0.45 | |
| | | | | | | | | | | | | | | | | |
| Weighted average common shares outstanding: | | | | | | | | | | | | | | | | |
| Basic | | | 25,185 | | | | 24,936 | | | | 25,163 | | | | 24,898 | |
| Diluted | | | 25,483 | | | | 25,446 | | | | 25,435 | | | | 25,406 | |
GOODRICH PETROLEUM CORPORATION
Selected Unaudited Cash Flow Data (In Thousands):
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| Calculation of EBITDAX: | | | | | | | | | | | | | | | | |
| Revenue | | | 28,006 | | | | 20,154 | | | | 51,548 | | | | 34,923 | |
| Lease operating expense | | | (6,310 | ) | | | (2,326 | ) | | | (10,421 | ) | | | (4,564 | ) |
| Production taxes | | | 750 | | | | (901 | ) | | | 432 | | | | (1,803 | ) |
| Transportation | | | (1,440 | ) | | | (1,488 | ) | | | (2,515 | ) | | | (1,488 | ) |
| G&A — cash portion only | | | (4,169 | ) | | | (2,789 | ) | | | (8,157 | ) | | | (5,628 | ) |
| Realized gain (loss) on derivatives not qualifying for hedge accounting | | | 1,040 | | | | 154 | | | | 4,827 | | | | (2,425 | ) |
| | | | | | | | | | | | | | | | | |
| EBITDAX | | | 17,877 | | | | 12,804 | | | | 35,714 | | | | 19,015 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of EBITDAX to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
| EBITDAX | | | 17,877 | | | | 12,804 | | | | 35,714 | | | | 19,015 | |
| EBITDAX — Discontinued Operations | | | 192 | | | | 5,951 | | | | 5,444 | | | | 14,405 | |
| Exploration | | | (1,767 | ) | | | (1,508 | ) | | | (4,093 | ) | | | (2,907 | ) |
| Prospect amortization | | | 1,261 | | | | 1,056 | | | | 3,432 | | | | 2,119 | |
| Dry hole costs | | | — | | | | — | | | | — | | | | — | |
| Interest expense | | | (2,222 | ) | | | (1,502 | ) | | | (4,846 | ) | | | (2,197 | ) |
| Other non-cash items | | | 53 | | | | 522 | | | | (405 | ) | | | 329 | |
| Net changes in working capital | | | 7,613 | | | | 11,908 | | | | 4,670 | | | | 24,240 | |
| | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities (GAAP) | | | 23,007 | | | | 29,231 | | | | 39,916 | | | | 55,004 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
| Discretionary cash flow | | | 15,394 | | | | 17,323 | | | | 35,246 | | | | 30,764 | |
| Net changes in working capital | | | 7,613 | | | | 11,908 | | | | 4,670 | | | | 24,240 | |
| Net cash provided by operating activities (GAAP) | | | 23,007 | | | | 29,231 | | | | 39,916 | | | | 55,004 | |
Selected Operating Data:
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| Production — Continuing Operations: | | | | | | | | | | | | | | | | |
| Natural gas (MMcf) | | | 3,549 | | | | 2,710 | | | | 6,744 | | | | 4,680 | |
| Oil and condensate (MBbls) | | | 28 | | | | 32 | | | | 54 | | | | 55 | |
| Total (Mmcfe) | | | 3,717 | | | | 2,902 | | | | 7,068 | | | | 5,010 | |
| | | | | | | | | | | | | | | | | |
| Average sales price per unit: | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 7.37 | | | $ | 6.57 | | | $ | 7.12 | | | $ | 6.61 | |
| Oil (per Bbl) | | | 61.06 | | | | 66.83 | | | | 58.97 | | | | 62.96 | |
| Natural gas and oil (Mcfe) | | | 7.50 | | | | 6.88 | | | | 7.24 | | | | 6.87 | |
| | | | | | | | | | | | | | | | | |
| Expenses per Mcfe: | | | | | | | | | | | | | | | | |
| Lease operating expense | | $ | 1.70 | | | $ | 0.80 | | | $ | 1.47 | | | $ | 0.91 | |
| DD&A | | | 5.24 | | | | 3.44 | | | | 5.26 | | | | 3.17 | |
| Exploration | | | 0.48 | | | | 0.52 | | | | 0.58 | | | | 0.58 | |
