Goodrich Reports 3Q07 Results
Goodrich Petroleum (NYSE: GDP) 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.
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 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.
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.
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