Prices realized during the first quarter of 2005 averaged $47.63 per barrel of oil and $6.00 per thousand cubic feet (Mcf) of natural gas as compared to first quarter 2004 average realized prices of $34.48 per barrel of oil and $5.49 per Mcf of natural gas. All unit pricing amounts include the cash settlement of hedging contracts. Hedging transactions in the first quarter of 2005 decreased the average realized price of natural gas by $0.19 per Mcf and oil by $0.33 per barrel.
Oil production during the first quarter of 2005 totaled approximately 1,357,000 barrels compared to first quarter 2004 oil production of approximately 1,544,000 barrels and fourth quarter 2004 oil production of approximately 984,000 barrels. Natural gas production during the first quarter of 2005 totaled approximately 15.2 billion cubic feet (Bcf), compared to first quarter 2004 natural gas production of approximately 14.6 Bcf and fourth quarter 2004 natural gas production of 13.5 Bcf. Daily production during the first quarter of 2005 averaged 260 MMcfe, or 23% higher than the average daily production in the fourth quarter of 2004.
Discretionary cash flow totaled $115.8 million during the first quarter of 2005, compared to $104.2 million during the first quarter of 2004. Net cash flow provided by operating activities, as defined by generally accepted accounting principles (GAAP), totaled $111.2 million during the first quarter of 2005, compared to $99.2 million in the first quarter of 2004. (Please see the accompanying financial statements for a reconciliation of discretionary cash flow, a non-GAAP financial measure, to net cash flow provided by operating activities.)
Lease operating expenses during the first quarter of 2005 totaled $27.9 million compared to $19.9 million for the comparable quarter in 2004. During the first quarter of 2005, lease operating expenses included $3.3 million of repairs in excess of estimated insurance recoveries related to Hurricane Ivan. The remaining $4.7 million increase in lease operating expenses for the first quarter of 2005 is primarily attributable to a 14% increase in the number of active wells and increases in overall industry service costs over the first quarter of 2004.
Depreciation, depletion and amortization (DD&A) on oil and gas properties for the first quarter of 2005 totaled $55.4 million compared to $46.0 million for the first quarter of 2004. The increase in DD&A for the first quarter of 2005 is the result of increases in the full-cycle unit cost of finding and developing proved reserves.
Salaries, general and administrative (SG&A) expenses for the first quarter of 2005 were $4.8 million compared to $3.7 million in the first quarter of 2004. The increase in SG&A expenses for the first quarter of 2005 is due primarily to a 10% increase in employment of technical personnel over the first quarter of 2004.
During the first quarter of 2005, Stone borrowed $76 million under our bank credit facility in connection with the closing of the previously announced acquisition of acreage in the Williston Basin of Montana and North Dakota. As of May 3, 2005, we have a borrowing base under the new bank credit facility of $425 million, of which $253.9 million of borrowings are currently available. As a result of bank borrowings and the issuance of $200 million 6 3/4% Senior Subordinated Notes during December 2004, interest expense increased to $5.6 million, net of $3.3 million capitalized, in the first quarter of 2005 compared to $3.9 million, net of $1.6 million of capitalized, in the first quarter of 2004.
Capital expenditures during the first quarter of 2005 totaled $201.9 million, including $102.5 million of acquisition costs, $5.2 million of capitalized general and administrative expenses and $3.3 million of capitalized interest.
During the first quarter of 2005, Stone drilled and evaluated 11 wells, five of which were productive. To date, Stone has spud 21 of the 81 wells planned for 2005. The following is an update of ongoing or recently completed operations:
Gulf of Mexico - Shelf & Onshore
Lafitte Field. The Rigolets LP No. A-1 Well was drilled to a total measured depth (MD) of 8,909 feet (8,325 feet of true vertical depth (TVD)) and encountered 120 feet of oil pay in seven sands and 21 feet of gas pay in another zone. The No. A-1 Well was dually completed in early April flowing at a combined gross rate of approximately 820 barrels of oil and 920 Mcf of gas per day. Stone has an approximate 100% working interest (WI) and an approximate 85% net revenue interest (NRI) in the well.
East Cameron Block 265. Following the Donut Prospect discovery of multiple shallow gas reservoirs between approximately 1,000 and 3,800 feet TVD in the No. 4 Well in July 2004 and the delineation drilling by the expendable No. 5 Well, the design and fabrication of a three-pile, six-slot production platform commenced. The "D" platform jacket was set over the No. 4 Well in approximately 175 feet of water in early March. Four development wells are planned and will be completed along with the No. 4 Well. During the drilling and completion phase, pipelines will be laid from the East Cameron Block 278 "B" platform to the "D" jacket. Stone expects the "D" platform deck to be installed during the third quarter of 2005 and first production during the fourth quarter of 2005. Stone has a 50% WI and a 40.7% NRI in these wells.
South Marsh Island Bock 192. The No. A-3 Well was drilled to a total depth of 17,631 feet (14,863 feet TVD) and logged approximately 86 feet of oil pay in three sands. The No. A-3 Well was designed as a development well for the productive horizons seen in the previously announced No. A-2 discovery of the Magic Prospect and to test a deeper section not reached in the No. A-2 Well. Modifications to the existing platform for oil-handling facilities are underway with first production from both wells estimated in the fourth quarter of 2005. Stone has a 50% WI and a 40.9% NRI in these wells.
South Timbalier Block 107. The No. 2 STK Well (Seaweed Prospect) reached a total depth of 16,791 feet MD in April and logged 83 feet of true vertical thickness (TVT) of gas pay in five sands. Completion operations are underway and production from the No. 2 STK Well is expected during the second quarter of 2005. Stone has a 30% non-operated WI and a 23.7% NRI in the well.
Viosca Knoll Block 817. The second well, in a multi-well program, drilled from an existing platform on Viosca Knoll Block 817 is currently completing. The No. A-2 STK2 Well reached a total depth of 11,106 feet MD (4,135 feet TVD) and logged 63 feet of TVT of gas pay in one zone. The first well, the A-1 STK2 Well, drilled to a total depth of 14,495 feet MD (11,333 feet TVD), and encountered 48 feet of net TVT pay in two zones. The No. A-1 STK2 Well was completed in a gas zone and is currently producing at a net daily rate of approximately 6.5 MMcf. A third well is planned from the platform during the second quarter of 2005. Operations to increase the compression capacity of the platform are underway and designed to allow for increased volumes of gas production from additional drilling. Stone has a 100% WI and a 70.3% NRI in the two wells drilled thus far in the program.
Pinedale Anticline. During the first quarter of 2005, Stone drilled one well on the Pinedale Anticline in the Greater Green River Basin of Wyoming, which is currently awaiting completion. We are currently utilizing a single drilling rig in the field due to wildlife restrictions. We plan to drill nine Pinedale wells during 2005. To date, we have drilled 20 successful wells and completed or are completing all of them. Stone has a 50% WI and a 41% NRI in the Pinedale project and is the operator of the drilling portion of the project. The project partner operates the completion and production phases.
Williston Basin. Stone has recently created a new core onshore oil area with the capture of approximately 148,000 net acres in the Williston Basin in a number of acquisitions that have closed or are under contract totaling approximately $96.7 million. On March 1, 2005, Stone completed the initial acquisition of approximately 35,000 net exploratory acres in the Williston Basin of North Dakota and Montana. The acquisition cost, net of purchase price adjustments, totaled approximately $85.7 million, of which $76.0 was financed with borrowings under Stone's bank credit facility. Approximately 80% of the net purchase price has been allocated to unevaluated costs. The first two wells, of approximately 15 wells planned for 2005, are currently drilling. Stone has working interests in this acreage ranging generally from 55% to 100%.
Production. Stone expects second quarter 2005 net daily production to average 260-280 MMcfe. Also, Stone expects full year 2005 production growth of 8%-16% over 2004 production volumes, which is a slight increase of the upper end of the range from the previous forecast of 8%-14%. Coincidentally, the revised full-year forecasted net daily production rates results in an average of 260-280 MMcfe, which is consistent with expected average net daily production for the second quarter of 2005.
Operating Expenses. For the second quarter of 2005, lease operating expenses are expected to total between $29-$32 million based upon known operating conditions and maintenance activities. Lease operating expenses, which include major maintenance costs, vary in response to changes in prices of service and materials used in the operation of our properties and the amount of maintenance activity required.
Estimates for Stone's future production are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of liquids and gas are complex processes that are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, earthquakes, and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production will be as estimated.
In this press release, we refer to a non-GAAP financial measure we call discretionary cash flow because of management's belief that this measure is a financial indicator of our company's ability to internally fund capital expenditures and service debt. Management also believes that this non-GAAP financial measure of cash flow is useful information to investors because it is widely used by professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Many investors use the published research of these analysts in making their investment decisions. Discretionary cash flow should not be considered an alternative to net cash provided by operating activities or net income, as defined by GAAP.
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