Prices realized during the second quarter of 2005 averaged $49.30 per barrel (Bbl) of oil and $6.50 per thousand cubic feet (Mcf) of natural gas, which represents a 19% increase, on an Mcfe basis, over second quarter 2004 average realized prices of $37.09 per Bbl of oil and $5.86 per Mcf of natural gas. Average realized prices during the first six months of 2005 were $48.54 per Bbl of oil and $6.26 per Mcf of natural gas representing a 20% increase on an Mcfe basis compared to $35.79 per Bbl of oil and $5.67 per Mcf of natural gas realized during the first six months of 2004. All unit pricing amounts include the cash settlement of hedging contracts.
During the second quarters of 2005 and 2004, hedging transactions reduced the average price we received for natural gas by $0.22 and $0.16 per Mcf, respectively. In addition, average realized oil prices were reduced by $0.59 per Bbl during the second quarter of 2005 as a result of hedges. Hedging transactions did not impact realized oil prices during the second quarter of 2004. Hedging transactions for natural gas during the first half of 2005 and 2004 decreased the average price we received for natural gas by $0.21 and $0.15 per Mcf, respectively. Average realized oil prices for the first half of 2005 were reduced by $0.47 as a result of hedges. There was no hedging impact on realized oil prices for the first half of 2004.
Net daily production volumes during the second quarter of 2005 averaged approximately 285 MMcfe which represented a 10% increase over average daily production for the first quarter of 2005 and a 9% increase over average daily production for the comparable quarter in 2004. For the six months ended June 30, 2005, net average daily production volumes were approximately 273 MMcfe, or 4% higher than average daily production for the six months ended June 30, 2004.
During the second quarter of 2005, discretionary cash flow increased 31% to $142.4 million compared to $108.8 million generated during the second quarter of 2004. Net cash flow provided by operating activities, as defined by generally accepted accounting principles (GAAP), totaled $139.5 million during the second quarter of 2005, compared to $89.1 million in the second quarter of 2004. For the first six months of 2005, discretionary cash flow totaled $258.3 million compared to $213.0 million for the comparable 2004 period. Net cash flow provided by operating activities totaled $250.7 million and $188.3 million during the six months ended June 30, 2005 and 2004, respectively. (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 second quarter of 2005 totaled $29.7 million compared to $22.9 million for the comparable quarter in 2004. For the six months ended June 30, 2005 and 2004, lease operating expenses were $57.6 million and $42.8 million, respectively. The increase in lease operating expenses during the second quarter of 2005 is primarily attributable to an increase in the number of active wells and increases in overall industry service costs over those in the second quarter of 2004.
Depreciation, depletion and amortization (DD&A) on oil and gas properties for the second quarter of 2005 totaled $65.0 million compared to $49.4 million for the second quarter of 2004. DD&A expense on oil and gas properties for the six months ended June 30, 2005 totaled $120.4 compared to $95.4 million during the same year-to-date period of 2004. The increase in DD&A for the second quarter of 2005 is the result of increases in the full-cycle unit cost of finding and developing proved reserves and the impact of drilling results.
Salaries, general and administrative (SG&A) expenses (exclusive of incentive compensation) for the second quarter of 2005 were $4.7 million compared to $3.5 million in the second quarter of 2004. For the six months ended June 30, 2005 and 2004, SG&A totaled $9.5 million and $7.3 million, respectively. The increase in SG&A is due primarily to an increase in employment of technical personnel during 2005 and salary adjustments.
As of August 1, 2005, we have a borrowing base under the new bank credit facility of $425 million, of which $273.9 million of borrowings are currently available. As a result of increased bank borrowings and the issuance of $200 million 6 3/4% Senior Subordinated Notes during December 2004, interest expense increased to $5.7 million, in the second quarter of 2005 compared to $4.0 million, in the second quarter of 2004. Interest expense totaled $11.3 million and $7.9 million during the six months ended June 30, 2005 and 2004, respectively.
Capital expenditures during the second quarter of 2005 totaled $103.2 million, including $23.0 million of acquisition costs, $4.7 million of capitalized general and administrative expenses (inclusive of incentive compensation) and $4.0 million of capitalized interest. Year-to-date 2005 additions to oil and gas property costs of $305.1 million include $125.6 million of acquisition costs, $9.9 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $7.3 million of capitalized interest. These investments were financed with cash flow from operating activities, working capital and bank borrowings.
During the second quarter of 2005, Stone drilled and evaluated 25 wells, 19 of which were productive. As of August 1, 2005, Stone has evaluated 38 of the 78 wells planned for 2005. The following is an update of ongoing or recently completed operations:
Gulf Coast Basin
During the second quarter of 2005, we evaluated 11 wells in the Gulf Coast Basin, nine of which were successful and two were dry holes. As of August 1, 2005, we are drilling one of the three wells planned for evaluation in the third quarter of 2005.
East Cameron Block 265. Four successful wells were drilled during the second quarter of 2005 to develop the July 2004 Donut Prospect discovery. Completion work on all five wells has begun and flow lines have been laid from the "D" Jacket to the "B" Platform. Construction of the deck is nearing completion and will be installed after all of the wells have been completed. First production is expected during the fourth quarter from all five wells barring significant weather delays. Stone has a 50% working interest (WI) and 40.7% net revenue interest (NRI) in these wells.
Viosca Knoll Block 817. Stone has completed the No. A-2 STK2 Well (Horse Prospect), which was a test of the F4 sand in a new fault block. The well reached a total measured depth (MD) of 10,950 feet (4,081 feet of true vertical depth (TVD)) during May. The No. A-2 STK2 Well logged 388 feet MD (63 feet true vertical thickness (TVT)) of gas pay in the objective sand. The well is flowing at an average daily rate of approximately 7 MMcfe.
Stone recently completed the drilling of the third and final well of the Viosca Knoll Block 817 program, the No. A-8 STK1 Well (Bison Prospect), designed to test multiple sands at a total depth of 6,460 MD feet (4,261 feet TVD). The No. A-8 STK1 Well logged a total of 118 feet MD (62 feet TVT) of gas pay in three zones. The well is currently being completed. Stone has a 100% WI and 70.3% NRI in these wells.
High Island Block A-568. The No. A-19 Well was drilled and completed from an existing platform during the second quarter of 2005 to a total depth of 12,651 feet MD (11,692 feet TVD) to test the Stealth Prospect. The No. A-19 Well logged a total of 90 feet (80 feet TVT) net gas pay in four sands ranging in depth from 6,000-8,000 feet MD (5,800-7,300 feet TVD), and an additional 16 feet (14 feet TVT) net gas pay in a deeper sand. The No. A-19 Well is currently producing at an average daily rate of approximately 15 MMcfe and 178 barrels of condensate. Stone has a 66.7% WI and 55.6% NRI in the well.
Garden Banks Block 171. The No. 1 Well to test the Kung Pao Prospect was drilled in 921 feet of water to a total depth of 17,594 feet MD in May and was plugged and abandoned as a dry hole. Stone had a 50% WI in the well.
Pinedale Anticline. During the second quarter of 2005 using a single rig program, Stone drilled the Rainbow No. 10-30D, which is currently being completed. Drilling operations are currently underway at the Antelope No. 10- 5D. With the lapse of seasonal restrictions on the Pinedale Anticline, five drilled wells are in the process of being completed with all completions anticipated to be finalized and related wells on production by the end of the quarter. Stone plans to drill three additional Pinedale wells during 2005. To date, 21 successful wells have been drilled and completed or are in the process of being completed. Stone has a 50% WI and 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.
Dugout Creek. In Carbon County of east central Utah, Stone acquired 27,000 net acres targeting the Ferron formation (the Dugout Creek project). Stone plans to drill three wells during 2005 to measured depths of 2,000-4,000 feet, with the first two wells currently being drilled and evaluated. Stone has a 100% WI and an 81% NRI in the Dugout Creek Project.
Williston Basin. As previously announced, Stone completed its first dual lateral horizontal well, the Bonnie 1-5H, in the Bakken fairway of Richland County, Montana. The well had an initial gross daily production rate of approximately 890 barrels of oil equivalent (BOE) from completions in both lateral wellbores. Stone's current daily production for the Williston Basin totals a net 804 BOE. Stone has reached total depth on a second dual lateral well, the Charles Nevin No. 1-12H, which is currently being completed in both lateral wellbores. Stone expects to drill 23 gross wells (approximately 12 net wells) during 2005 with three rigs currently running in the basin.
Production. Stone expects third quarter 2005 net daily production to average 260-280 MMcfe, which includes the impact of shut-ins from Tropical Storm Cindy and Hurricane Dennis as well as an estimate for other potential storm related interruptions. Stone expects full year 2005 net average daily production rates of 260-280 MMcfe.
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.
Operating Expenses. For the third quarter of 2005, lease operating expenses are expected to total between $29-33 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. Therefore, we can give no assurance that our future operating expenses 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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