808 Travis, Suite 1320
Houston, Texas 77002
(713) 780-9494
Fax (713) 780-9254
Contact:
| Robert C. Turnham, Jr., President | Traded: NYSE (GDP) |
FOR IMMEDIATE RELEASE
GOODRICH PETROLEUM ANNOUNCES THIRD QUARTER
FINANCIAL AND OPERATIONAL RESULTS
| · | Net Production Volumes Averaged 46,500 Mcfe Per Day for the Quarter, Representing 14% Sequential Growth and 40% Growth Over the Prior Year Period |
| · | Gross Cotton Valley Trend Production Volumes Increased by 16% Sequentially and 54% Over the Prior Year Period to 80,000 Mcfe Per Day |
| · | Cash Flow (EBITDAX) Increased by 71% From the Prior Year Period and 8% Sequentially to $19.2 Million |
| · | LOE Per Mcfe Reduced by 28% Sequentially |
| · | DD&A Per Mcfe Reduced by $0.47 Sequentially |
| · | Net Income Negatively Impacted by $14.8 Million Non-Cash Adjustment to Deferred Tax Asset |
Houston, Texas - November 7, 2007. Goodrich Petroleum Corporation today announced its financial and operating results for the third quarter ended September 30, 2007.
Given the sale of most of the Company’s south Louisiana assets in the first 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 September 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 $9.8 million gain after tax on the sale of the assets in the first nine months of the year, and another $2.1 million in after tax income from the discontinued operations during the nine month period.
Net Income (loss) for the quarter was a loss of $22.1 million versus net income of $8.2 million for the third quarter of 2006. Net loss applicable to common stock for the quarter was $23.7 million, or ($0.94) per basic share, compared to net income applicable to common stock for the third quarter of 2006 of $6.7 million, or $0.27 per basic share. Net loss for the 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”).
In determining the carrying value of a deferred tax asset, SFAS 109 provides for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2006 and prior years, and current conditions appear to indicate a loss in 2007, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, with the before mentioned adjustment of $14.8 million, we have reduced the carrying value of our net deferred tax asset to zero. If we achieve profitable operations in the future, we may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if we generate taxable income in future periods, we will be able to utilize our NOL’s to offset taxes due at that time. The Company’s NOL position at year end 2006 stood at approximately $73.8 million.
Earnings before interest, taxes, DD&A and exploration ("EBITDAX") for the quarter increased by 71% to $19.2 million, compared to $11.2 million in the third quarter of 2006. EBITDAX increased by 8% sequentially over the second quarter of 2007. Sequentially, third quarter EBITDAX was positively impacted by increased production volumes, coupled with an 8.5% reduction in costs per Mcfe, partially offset by an 8% reduction in oil and gas prices after taking into effect realized oil and gas hedges (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 $6.09 per Mcf before the impact of settled derivative contracts, or approximately $0.07 below the 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 $7.13 per Mcf. For crude oil, the realized price during the quarter was $73.32 per barrel before the impact of settled derivative contracts, and $52.95 per barrel including the impact of settled derivatives.
Discretionary cash flow (“DCF”), defined as net cash provided by operating activities before changes in working capital, increased to $17.1 million for the third quarter, which represents 11% sequential growth over 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).
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 $8.5 million for the quarter, versus an operating loss of $2.2 million in the third quarter of 2006.
Gain (loss) on derivatives not qualifying for hedge accounting. The Company had a gain on derivatives not qualifying for hedge accounting for the quarter of $2.4 million, due largely to a realized gain of $3.6 million for the effect of settled derivatives. The realized gain of $3.6 million was comprised of a gain of $4.2 million on natural gas settlements and a loss of $0.6 million on the Company’s oil settlements.
The quarter’s derivatives gain was negatively impacted by an unrealized loss of $0.9 million due to the change in fair value of the Company’s ineffective oil and gas hedges and a $0.3 million loss on the Company’s interest rate swap. For comparative purposes, during the third quarter of 2006 the Company recorded a gain on derivatives not qualifying for hedge accounting of $15.2 million before taxes.
All of the Company’s oil hedges expire with the expiration of the December 2007 contract and the Company currently has 33,500 MMBtu per day of natural gas hedged in 2008 at a blended average NYMEX equivalent floor price of $8.20 and 20,000 MMBtu per day of natural gas hedged in 2009 at an $8.25 NYMEX equivalent price.
OPERATING EXPENSES
Lease operating expense ("LOE") for the quarter was $5.2 million, or $1.22 per Mcfe, compared to $3.9 million, or $1.27 per Mcfe for the third quarter of 2006. LOE decreased in absolute terms by 17% sequentially and by 28% per Mcfe, from a second quarter expense of $6.3 million, or $1.70 per Mcfe. The base LOE for the quarter, after deducting workover costs of $0.5 million, decreased by 18% sequentially, to $1.11 per Mcfe, compared to a base LOE of $1.35 per Mcfe in the second quarter of 2007. During the quarter, we began to experience the benefit of our new low pressure gathering system (“LPGS”) in East Texas, with salt water disposal (“SWD”) costs falling 30% on a per Mcfe basis, from $1.8 million (or $0.47 per Mcfe of production) in the second quarter of 2007 to $1.4 million (or $0.33 per Mcfe of production) for the third quarter. As additional SWD cost reduction projects are phased in at the Company’s other major fields, the Company expects to see continued improvement in this expense category, with total LOE per Mcfe approaching $1.00 as the Company exits December 2007.
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 quarter, DD&A expense was $20.4 million, or $4.77 per Mcfe, which represented a $0.47 per Mcfe decrease versus the $5.24 per Mcfe, or $19.5 million, recognized in the second quarter of 2007. DD&A expense in the year ago period was $9.8 million, or $3.20 per Mcfe. Both absolute dollar and per Mcfe DD&A measures for the third quarter of 2007 were higher than the year ago period, due primarily to higher production rates and a higher percentage of production coming from fields with higher average DD&A rates.
General and administrative ("G&A") expense decreased by approximately 20% sequentially on a per Mcfe basis in the quarter to $5.1 million, or $1.18 per Mcfe, versus $5.5 million, or $1.48 per Mcfe in the second quarter of 2007. The reduction in G&A per Mcfe was largely driven by an 8% reduction in expenses and increased production volumes. G&A per Mcfe for the quarter decreased by approximately 16% versus the prior year period expense of $4.3 million, or $1.40 per Mcfe. Stock based compensation, which is a non-cash item included in G&A, amounted to $1.6 million for the quarter, or 31% of the total.
Production and other taxes for the quarter was $1.3 million, or $0.30 per Mcfe, versus $1.0 million, or $0.34 per Mcfe in the third quarter of 2006. Production and other taxes for the quarter consisted of $0.6 million of production taxes and $0.7 million of ad valorem taxes. Production taxes included $0.4 million of accrued Tight Gas Sands (“TGS”) credits for the Company’s wells in the State of Texas. Ad valorem taxes included a $0.6 million charge in the third quarter to adjust for full year 2007 anticipated taxes. During the third quarter of 2006, production and ad valorem taxes totaled $0.8 million and $0.2 million, respectively.
Exploration expense per Mcfe decreased by 18% to $1.8 million during the quarter, or $0.41 per Mcfe, versus $1.5 million, or $0.50 per Mcfe in the prior year period. Exploration expense per Mcfe decreased sequentially by approximately 16% in the quarter, versus second quarter exploration expense of $1.8 million, or $0.48 per Mcfe. Non-cash leasehold amortization costs represented $1.5 million, or 83%, of the total exploration expense for the quarter, as all of the Company’s undeveloped Cotton Valley Trend acreage is captured in exploration expense and amortized over a three year period.
Impairment of oil and gas properties for the quarter totaled $0.3 million due to the receipt of the independent engineer’s mid-year report on reserves. All of the expense relates to a single well in a non-core area of East Texas.
CAPITAL EXPENDITURES
Capital expenditures for the quarter totaled $81.3 million compared to $52.6 million in the third quarter of 2006. Of the $81.3 million, $77.4 million was incurred on the drilling and completion of Cotton Valley Trend wells during the quarter, $1.1 million was incurred on infrastructure and $2.8 million was incurred on leasehold acquisitions in the Cotton Valley Trend. Although the Company conducted drilling and/or completion operations on 36 gross wells during the quarter, capital expenditures in excess of $0.25 million per well were accrued on over 56 wells during this period. The Company funded its capital expenditures in the quarter through a combination of cash flow from operations, draws under its bank revolver, and available cash.
OPERATIONS
Production for the quarter from continuing operations was 4.3 Bcfe, or approximately 46,500 Mcfe per day, representing a 40% increase over the prior year period volumes of 3.1 Bcfe or 33,300 Mcfe per day. Sequentially, production volumes increased by 14% over production volumes for the second quarter of 2007. 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 50,000 to 52,000 Mcfe per day, or approximately 7% - 11% sequential growth over the third quarter.
Drilling operations continued at an aggressive pace in the Cotton Valley Trend, with the Company conducting drilling operations on 36 wells with an average of approximately ten rigs (nine of which were operated) running full time in the quarter. The Company completed 32 wells in five fields during the quarter, with an average gross initial production rate of approximately 2,000 Mcfe per day, versus the historical average of 1,700 Mcfe per day. Current average gross initial production rate for the wells drilled from inception to date has increased by 100 Mcfe per day to 1,800 Mcfe per day.
Year to date, the Company has completed 66 wells, with an average initial production rate of approximately 2,100 Mcfe per day, or a 23% increase versus the historical average of 1,700 Mcfe per day, with 10 wells in completion stage but not producing on September 30, 2007. Field by field initial production rates for the wells completed in 2007 through the third quarter, are as follows:
| | | Field | No. of Wells | Initial Production Rate |
| | | | | |
| | · | Minden | 18 | 1,600 Mcfe/day |
| | · | Dirgin-Beckville | 10 | 2,200 Mcfe/day |
| | · | Bethany-Longstreet | 11 | 2,200 Mcfe/day |
| | · | South Henderson | 8 | 2,100 Mcfe/day |
| | · | Angelina River | 17 | 2,700 Mcfe/day |
| | · | Other | 2 | 900 Mcfe/day |
At September 30, 2007, the Company had 218 wells producing in the Cotton Valley Trend and 10 being completed, with an average 198 producing for the entire quarter at an average gross rate of approximately 400 Mcfe per day. The Company has drilled and logged 228 wells in the Cotton Valley Trend with in excess of a 99% success rate. The 228 wells were drilled and logged at the following fields:
| | | Field | No. of Wells | |
| | | | | |
| | · | Minden | 82 | |
| | · | Dirgin Beckville | 61 | |
| | · | Bethany Longstreet | 25 | |
| | · | South Henderson | 17 | |
| | · | Angelina River Trend | 30 | |
| | · | Others | 13 | |
Cotton Valley Trend acreage at September 30, 2007 was approximately 184,000 gross and 112,000 net acres.
SPECIFIC FIELD UPDATES
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 three wells, with all three wells having the Cotton Valley and Hosston present. One of the wells, the Jimmy Holmes 1-H, the Company’s initial horizontal re-entry of an existing wellbore in the field is currently flowing back at approximately 475 Mcf per day with 54% of the frac fluid recovered. Flowback from the well has been much slower than expected primarily due to the small diameter tubing used in the completion. The Company currently has plans to spud its second new horizontal well in the field, the Champe Graham 5-H, by the end of the year.
The Champe Graham No. 3-H, the Company’s initial horizontal well in the field, has now been online and producing in excess of seven months, with a current rate of approximately 1,500 Mcf per day. The production performance to date fits the Company’s mid-year reserve decline curve and estimate of 4.4 Bcfe.
The Company has continued to add to its acreage in the field, and currently owns a 70% working interest in 28,000 gross acres.
Caddo Parish Joint Venture - Longwood Field
Caddo Parish, Louisiana
The Company has spudded its initial horizontal Cotton Valley sand test well, the Mitchell 1-H, on its Caddo Parish Joint Venture in the Longwood field of Caddo Parish, Louisiana. The Company intends to drill a 3,000 foot horizontal lateral in the Sexton sand of the Cotton Valley formation. The Company will own a 75% working interest in the initial well and a 67.5% working interest in approximately 19,500 gross acres, (resulting in the Company earning 6,400 net acres). The field is north of and on trend with the Company’s Bethany-Longstreet field in Caddo and DeSoto Parishes.
Angelina River Trend
Angelina and Nacogdoches Counties, Texas
The Company completed 11 wells in the Angelina River Trend during the quarter, with an average gross initial production rate of 2,600 Mcf per day. Gross Angelina River Trend volumes grew 76% and net grew 69% sequentially over the second quarter, comprising 16% of the Company’s net third quarter volumes. The Company currently has three rigs running on its 67,500 gross (33,000 net) acres, with two operated and one non-operated.
Cotton and Allentown Prospect Areas - James Lime Horizontals
The Company has reached total depth on its second horizontal James Lime well in the Cotton Prospect area of the Angelina River Trend, the USA LB 1-H. The well was drilled with an approximate 6,600 foot lateral. The Company owns a 40% non-operated working interest in the well.
The Company has also spudded its Wilson 4-H horizontal James Lime well on its Allentown Prospect area of the Angelina River Trend. The well is planned for a 6,500 foot lateral and the Company owns an 80% interest. The Company is currently drilling the horizontal lateral section of the well and expects to reach total depth in approximately seven days.
Cotton South Prospect Area - Travis Peak
The Company participated in drilling and completion operations on eight Travis Peak vertical wells on the Cotton South Prospect area in the Angelina River Trend during the quarter, with an average initial production rate of 2,750 Mcf per day.
Bethune Prospect Area - Travis Peak
During the third quarter the Company continued to prove up its acreage in the Bethune Prospect area of the Angelina River Trend with the drilling of two additional Travis Peak wells and the completion of the Bethune A-1 well, which had an initial production rate of 3,300 Mcf per day.
Commenting on the quarter, Vice Chairman and CEO, Gil Goodrich, stated “The third quarter was an excellent quarter for us in many respects - volume growth, cost reductions, and continued success in the development of our core properties. We were very active during the quarter, as we invested $81 million in new wells, infrastructure and leasehold acquisitions. Our drilling program allowed us to achieve solid production growth in the quarter, which fully replaced the production volumes associated with the sale of our South Louisiana assets in March. Our drilling activities in the Angelina River Trend continue to be a significant growth catalyst, as we continued to prove up additional acreage in the Trend with vertical Travis Peak and horizontal James Lime development. As a result of our efforts in this area, our net daily production volumes from Angelina River Trend wells grew by 69% sequentially over the second quarter of this year. We will remain very active in this area, with on-going development of both the Travis Peak and James Lime, as we expect to have three to four rigs active in the Trend. In addition to the Angelina River Trend activities, we remain encouraged by the results from our other growth catalysts, including increased density drilling, surgical frac technology and horizontal drilling technology, having recently commenced drilling operations on our A.C Mitchell No.1 well which is a horizontal Cotton Valley sand test in northwest Louisiana. The combination of growing production volumes, decreasing costs on a per unit basis, the improvements we are seeing in the market for oilfield goods and services, as well as our existing natural gas hedge position, has us extremely excited about the opportunity for expanding our cash margins further in 2008.”
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 INCOME DATA | |
| (In Thousands, Except Per Share Amounts) | |
| | | | | | | | | | |
| | | Three Months Ended | Nine Months Ended | |
| | | September 30, | September 30, | |
| | | 2007 | | 2006 | | 2007 | | 2006 | |
| | | | | | | | | | |
| Total Revenues | | $ | 27,280 | | $ | 19,624 | | $ | 78,828 | | $ | 54,547 | |
| Operating Expenses | | | | | | | | | | | | | |
| Lease operating expense | | | 5,215 | | | 3,891 | | | 15,500 | | | 8,274 | |
| Production and other taxes | | | 1,292 | | | 1,039 | | | 996 | | | 3,023 | |
| Transportation | | | 1,715 | | | 1,229 | | | 4,230 | | | 2,717 | |
| Depreciation, depletion and amortization | | | 20,434 | | | 9,821 | | | 57,603 | | | 25,687 | |
| Exploration | | | 1,754 | | | 1,528 | | | 5,847 | | | 4,435 | |
| General and administrative | | | 5,054 | | | 4,282 | | | 15,892 | | | 12,248 | |
| Impairment of oil and gas properties | | | 282 | | | - | | | 282 | | | - | |
| Operating income (loss) | | | (8,466 | ) | | (2,166 | ) | | (21,522 | ) | | (1,837 | ) |
| Other income (expense) | | | | | | | | | | | | | |
| Interest expense | | | (3,086 | ) | | (2,509 | ) | | (7,932 | ) | | (4,706 | ) |
| Gain (loss) on derivatives not qualifying for hedge accounting | | | 2,378 | | | 15,188 | | | (3,475 | ) | | 34,611 | |
| | | | (708 | ) | | 12,679 | | | (11,407 | ) | | 29,905 | |
| Income (loss) from continuing operations before income taxes | | | (9,174 | ) | | 10,513 | | | (32,929 | ) | | 28,068 | |
| Income tax (expense) benefit | | | (11,641 | ) | | (3,669 | ) | | (3,379 | ) | | (9,779 | ) |
| Income (loss) from continuing operations | | | (20,815 | ) | | 6,844 | | | (36,308 | ) | | 18,289 | |
| Discontinued operations: | | | | | | | | | | | | | |
| Gain (loss) on disposal, net of tax | | | (928 | ) | | - | | | 9,823 | | | - | |
| Income (loss) from discontinued operations, net of tax | | | (401 | ) | | 1,337 | | | 2,078 | | | 5,782 | |
| | | | (1,329 | ) | | 1,337 | | | 11,901 | | | 5,782 | |
| Net income (loss) | | | (22,144 | ) | | 8,181 | | | (24,407 | ) | | 24,071 | |
| Preferred stock dividends | | | 1,511 | | | 1,511 | | | 4,535 | | | 4,504 | |
| Preferred stock redemption premium | | | - | | | - | | | - | | | 1,545 | |
| Net income (loss) applicable to common stock | | $ | (23,655 | ) | $ | 6,670 | | $ | (28,942 | ) | $ | 18,022 | |
| | | | | | | | | | | | | | |
| Income (loss) per common share from continuing operations | | | | | | | | | | | | | |
| Basic | | $ | (0.83 | ) | $ | 0.27 | | $ | (1.44 | ) | $ | 0.73 | |
| Diluted | | $ | (0.83 | ) | $ | 0.27 | | $ | (1.44 | ) | $ | 0.72 | |
| Income (loss) per common share from discontinued operations | | | | | | | | | | | | | |
| Basic | | $ | (0.05 | ) | $ | 0.05 | | $ | 0.47 | | $ | 0.23 | |
| Diluted | | $ | (0.05 | ) | $ | 0.05 | | $ | 0.47 | | $ | 0.23 | |
| Net income (loss) per common share applicable to common stock | | | | | | | | | | | | | |
| Basic | | $ | (0.94 | ) | $ | 0.27 | | $ | (1.15 | ) | $ | 0.72 | |
| Diluted | | $ | (0.94 | ) | $ | 0.26 | | $ | (1.15 | ) | $ | 0.71 | |
| Weighted average common shares outstanding: | | | | | | | | | | | | | |
| Basic | | | 25,204 | | | 24,972 | | | 25,177 | | | 24,923 | |
| Diluted | | | 25,204 | | | 25,346 | | | 25,177 | | | 25,386 | |
| | | | | | | | | | | | |
| GOODRICH PETROLEUM CORPORATION | |
| | | | | | | | | | | | |
| Selected Cash Flow Data (In Thousands): | | | | | | | | | | | |
| | | | | Three Months Ended | | Nine Months Ended | |
| | | | | September 30, | | September 30, | |
| | | | | 2007 | | 2006 | | 2007 | | 2006 | |
| | | | | | | | | | | | |
| Calculation of EBITDAX: | | | | | | | | | | | |
| Revenue | | | | | $ | 27,280 | | $ | 19,624 | | $ | 78,828 | | $ | 54,547 | |
| Lease operating expense | | | | | | (5,215 | ) | | (3,891 | ) | | (15,500 | ) | | (8,274 | ) |
| Production and other taxes | | | | | | (1,292 | ) | | (1,039 | ) | | (996 | ) | | (3,023 | ) |
| Transportation | | | | | | (1,715 | ) | | (1,229 | ) | | (4,230 | ) | | (2,717 | ) |
| G&A - cash portion only | | | | | | (3,485 | ) | | (2,926 | ) | | (11,642 | ) | | (8,554 | ) |
| Realized gain (loss) on derivatives not qualifying for | | | | | | | | | | | | | | | | |
| hedge accounting | | | | | | 3,672 | | | 666 | | | 8,499 | | | (1,759 | ) |
| | | | | | | | | | | | | | | | | |
| EBITDAX | | | | | $ | 19,245 | | $ | 11,205 | | $ | 54,959 | | $ | 30,220 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of EBITDAX to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
| EBITDAX | | | | | $ | 19,245 | | $ | 11,205 | | $ | 54,959 | | $ | 30,220 | |
| EBITDAX - Discontinued Operations | | | | | | 302 | | | 6,735 | | | 5,746 | | | 21,140 | |
| Exploration | | | | | | (1,754 | ) | | (1,528 | ) | | (5,847 | ) | | (4,435 | ) |
| Prospect amortization | | | | | | 1,663 | | | 1,790 | | | 5,095 | | | 3,909 | |
| Dry hole costs | | | | | | - | | | - | | | - | | | - | |
| Interest expense | | | | | | (3,086 | ) | | (2,509 | ) | | (7,932 | ) | | (4,706 | ) |
| Other non-cash items | | | | | | 805 | | | (866 | ) | | 400 | | | (537 | ) |
| Net changes in working capital | | | | | | 4,497 | | | (17,378 | ) | | 9,167 | | | 6,862 | |
| | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities (GAAP) | | | | | $ | 21,672 | | $ | (2,551 | ) | $ | 61,588 | | $ | 52,453 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities: | | | | | | | | | | | | | | | | |
| Discretionary cash flow | | | | | $ | 17,175 | | $ | 14,827 | | $ | 52,421 | | $ | 45,591 | |
| Net changes in working capital | | | | | | 4,497 | | | (17,378 | ) | | 9,167 | | | 6,862 | |
| Net cash provided by operating activities (GAAP) | | | | | | 21,672 | | | (2,551 | ) | | 61,588 | | | 52,453 | |
| | | | | | | | | | | | | | | | | |
| Selected Operating Data: | | | | | | | | | | | | | | | | |
| | | | | | | Three Months Ended | | | Nine Months Ended | |
| | | | | | | September 30, | | | September 30, | |
| | | | | | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | |
| Production - Continuing Operations: | | | | | | | | | | | | | | | | |
| Natural gas (MMcf) | | | | | | 4,101 | | | 2,910 | | | 10,846 | | | 7,590 | |
| Oil and condensate (MBbls) | | | | | | 30 | | | 26 | | | 84 | | | 81 | |
| Total (Mmcfe) | | | | | | 4,282 | | | 3,066 | | | 11,349 | | | 8,076 | |
| | | | | | | | | | | | | | | | | |
| Average sales price per unit: | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | | | | $ | 6.09 | | $ | 6.07 | | $ | 6.73 | | $ | 6.41 | |
| Oil (per Bbl) | | | | | | 73.32 | | | 68.50 | | | 64.12 | | | 64.75 | |
| Natural gas and oil (Mcfe) | | | | | | 6.34 | | | 6.35 | | | 6.90 | | | 6.67 | |
| | | | | | | | | | | | | | | | | |
| Expenses per Mcfe: | | | | | | | | | | | | | | | | |
| Lease operating expense | | | | | $ | 1.22 | | $ | 1.27 | | $ | 1.37 | | $ | 1.02 | |
| DD&A | | | | | | 4.77 | | | 3.20 | | | 5.08 | | | 3.18 | |
| Exploration | | | | | | 0.41 | | | 0.50 | | | 0.52 | | | 0.55 | |
