Nov. 5, 2009 (PR Newswire) --
DENVER, Nov. 5 /PRNewswire-FirstCall/ -- Delta Petroleum Corporation (Nasdaq: DPTR), an independent oil and gas exploration and development company, announced its financial and operating results for the third quarter of 2009.
GRAY 31-23 COMPLETION RESULTS
Delta has finished completion efforts on the Gray well. As previously announced, while all zones encountered significant high pressure, they flowed primarily water with minor amounts of non-commercial associated gas. Additional testing was performed in the basalt section of the well with a similar outcome, and therefore the Gray well has been expensed as a dry hole in the Company's third quarter financial statements.
Delta's Columbia River Basin team has reviewed available data in order to provide possible explanations regarding the lack of commercial gas from the Wenatchee sands of the Gray well. One of the challenges generally experienced in the industry is the fact that fresh water and hydrocarbons are almost indistinguishable on electric logs. Therefore the gas shows and over-pressured reservoir seen in the Gray well during drilling suggested a gas reservoir with some associated water; however, completion results instead revealed that the reservoir is a fresh water reservoir with some associated natural gas.
The lessons learned from the drilling of the Gray well have provided the Company with important and strategic information that will be of benefit in any future drilling operations in the Columbia River Basin. Numerous issues related to drilling through the basalt formation were identified, analyzed and explained, and management believes that this information can be translated into potentially significant savings of both cost and time in the future. While gas was liberated, no source rock was drilled in this well, thus Delta's primary objective, the deeper Roslyn formation, remains a viable target.
John Wallace, the Company's President and COO said, "We are extremely disappointed with the results of the Gray well, but exploration drilling carries with it significant risks. We continue to believe that the Roslyn formation, which has produced elsewhere in the Columbia River Basin, has significant potential and should be tested. In addition, data obtained during the drilling of the Gray well has allowed for better seismic interpretation that can now be applied to the Company's leasehold in the basin. A more accurate representation of the structural configuration below the basalt section, including the Roslyn formation, will help direct us to more precise geologic prospects and potential future well locations."
"While much attention was paid to the drilling and completion of the Gray well, we want to highlight to our stockholders where the intrinsic value lies within Delta. Delta's operational strength is in the Rockies and go forward strategy focused on lower-risk development projects will allow the Company to realize consistent, efficient reserve and production growth in the Piceance Basin, once natural gas prices recover. We believe that we have the track record, experience and assets that will allow us to execute this strategy."
Dan Taylor, the Company's Chairman stated, "Delta will continue to strive to deliver value to our shareholders through the development of our core assets and the execution of our cost control strategy. I concur with John on the underlying value of Delta being our proved and probable reserves in the Piceance Basin, which are not adequately reflected in our current share price."
BORROWING BASE REDETERMINATION
On October 30, 2009, the Company and its senior lenders completed the borrowing base re-determination under the Company's revolving credit facility. As part of the redetermination, the Company and its lenders entered into an amendment to the credit facility pursuant to which the lenders provided waivers from the December 31, 2009 and March 31, 2010 current ratio and consolidated secured debt to EBITDAX ratio covenants, and the borrowing base was reduced from $225.0 million to $185.0 million. The amendment requires that Delta maintain minimum availability of $20.0 million essentially reducing Delta's availability under the credit facility. In addition, capital expenditures will be limited to $10.0 million for the quarter ended December 31, 2009, $10.0 million for the quarter ended March 31, 2010, and $5.0 million for the quarter ended June 30, 2010, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier quarter to a subsequent quarter. The next scheduled re-determination is March 1, 2010.
RESULTS FOR THE THIRD QUARTER
For the quarter ended September 30, 2009, the Company reported production of 5.14 billion cubic feet equivalents (Bcfe), a decrease of 22% when compared with the third quarter of 2008 and a decrease of 10% when compared with the second quarter of 2009. Total revenue decreased 67% to $23.9 million in the quarter, versus revenue of $72.0 million in the quarter ended September 30, 2008. Revenue from oil and gas sales declined 64% to $21.5 million, compared with $60.3 million in the prior year quarter. The decrease was principally the result of a 44% decrease in oil prices received, a 60% decrease in natural gas prices received, and a 22% decrease in production. The average oil price received during the three months ended September 30, 2009 decreased to $61.43 per Bbl compared to $110.49 per Bbl for the year earlier period. The average natural gas price received during the three months ended September 30, 2009 decreased to $2.59 per Mcf compared to $6.49 per Mcf for the year earlier period. The production decrease was primarily related to production declines in the Rockies that have not been offset by additional drilling. Revenue from contract drilling and trucking fees decreased 78% to $2.5 million in the current quarter, versus $11.8 million in the third quarter of 2008. The decrease is the result of lower third party rig utilization in the three months ended September 30, 2009 compared to the comparable year earlier period, resulting from a significant industry slowdown attributable to lower commodity prices.
The Company reported a third quarter net loss attributable to Delta common stockholders of ($96.8 million), or ($0.35) per diluted share, compared with net income attributable to Delta common stockholders of $48.8 million, or $0.47 per diluted share, in the third quarter of 2008. The increased loss was primarily due to impairments recorded in the third quarter of 2009 and significantly lower natural gas and oil prices compared to the same period prior year.
THIRD QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per thousand cubic feet equivalent (Mcfe) for the three months ended September 30, 2009 and 2008 are as follows:
Three Months Ended
September 30,
--------------------
2009 2008
---- ----
Production - Continuing Operations:
Oil (Mbbl) 180 247
Gas (Mmcf) 4,059 5,089
Total Production (Mmcfe) 5,137 6,569
Average Price - Continuing Operations:
Oil (per barrel) $61.43 $110.49
Gas (per Mcf) $2.59 $6.49
Costs per Mcfe - Continuing Operations:
Lease operating expense $1.47 $1.17
Production taxes $0.23 $0.59
Transportation costs $0.41 $0.55
Depletion expense $4.86 $4.40
Realized derivative gains $0.07 $1.65
Lease operating expense. Lease operating expense for the quarter ended September 30, 2009 decreased to $7.6 million from $7.7 million in the year earlier period. Lease operating expense from continuing operations per Mcfe for the three months ended September 30, 2009 increased to $1.47 per Mcfe from $1.17 per Mcfe for the comparable year earlier period, primarily as a result of lower production volumes.
Depreciation, depletion and amortization expense. Oil and gas depreciation, depletion and amortization expense decreased 13% to $25.7 million for the three months ended September 30, 2009, as compared to $29.6 million for the same period prior year. Depletion expense for the three months ended September 30, 2009 was $25.0 million compared to $28.9 million for the three months ended September 30, 2008. Our depletion rate increased from $4.40 per Mcfe for the three months ended September 30, 2008 to $4.86 per Mcfe for the current year period primarily due to the effect of low spot commodity prices at September 30, 2009 on the reserves used in our depletion calculation, offset by the effect of impairments recorded in the fourth quarter of 2008.
Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of approximately $53.4 million for the three months ended September 30, 2009 compared to $8.1 million for the comparable period a year ago. During the three months ended September 30, 2009, dry hole and impairment costs primarily related to the Gray 31-23 in the Columbia River Basin which was completed during the third quarter of 2009, but found to be uneconomic resulting in dry hole costs of $31.0 million and Columbia River Basin unproved leasehold impairments of $20.4 million. In addition, $2.1 million of other impairments were recorded, most of which related to a proved property impairment for the Angleton property in Texas.
The Company incurred dry hole costs of approximately $8.1 million for the three months ended September 30, 2008 primarily related to four wells, one well in Wyoming, one well in California, one well in Utah and a non-operated well in the Columbia River Basin. No impairments were recorded during the three months ended September 30, 2008.
General and Administrative Expense. General and administrative expense decreased 33% to $10.0 million for the three months ended September 30, 2009, as compared to $14.9 million for the comparable prior year period. The decrease in general and administrative expense is attributed to reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense and a decrease in non-cash stock compensation expense from lower executive performance share costs, and also from forfeitures and modifications of salaries related to the reductions in force which affected approximately fifty percent of personnel.
RESULTS FOR THE NINE MONTHS
For the nine months ended September 30, 2009, the Company reported production of 17.2 Bcfe, a decrease of 5% when compared with the nine months ended September 30, 2008. Total revenue decreased 52% to $105.5 million in the nine months ended September 30, 2009, versus revenue of $217.6 million in the nine months ended September 30, 2008. Revenue from oil and gas sales declined 65% to $65.0 million, compared with $187.3 million in the prior year period. The decrease was principally the result of a 54% decrease in oil prices received, a 66% decrease in natural gas prices received and a 5% decrease in production. The average oil price received during the nine months ended September 30, 2009 decreased to $47.90 per Bbl compared to $105.17 per Bbl for the year earlier period. The average natural gas price received during the nine months ended September 30, 2009 decreased to $2.69 per Mcf compared to $7.93 per Mcf for the year earlier period. Revenue from contract drilling and trucking fees decreased to $9.4 million compared to $30.4 million for the same period in the prior year. The decrease is the result of lower third party rig utilization in the nine months ended September 30, 2009 compared to the comparable year earlier period, resulting from a significant industry slowdown attributable to lower commodity prices.
The Company reported a nine month net loss attributable to common stockholders of ($294.7 million), or ($1.55) per diluted common share, compared with a net income attributable to common stockholders of $4.6 million, or $0.05 per diluted share, for the nine months ended September 30, 2008.
