Release Date: September 24, 2003
Upton Resources Inc. – Cash Flow and Production Strong, Debt Drops $7.5 Million
09:00 EDT Friday, August 15, 2003
(URC – TSX)
CALGARY, Aug. 15 /CNW Telbec/ – Upton Resources Inc. (“Upton”) is pleased to announce its second quarter financial and operating results, and to update its process to maximize shareholder value. Second quarter cash flow from operations was $9.6 million and $0.46 basic per share, and earnings were $2.0 million and $0.10 basic per share. Production was 5,633 barrels of oil equivalent per day (boepd), net debt decreased $7.5 million in the quarter, while capital expenditures were $2.2 million. New reserve additions were 512,000 barrels, primarily at Queensdale, southeast Saskatchewan; a result of newly negotiated lease line agreements for wells scheduled to be drilled in the third and fourth quarters. Upton achieved excellent performance in the face of crude prices which dropped from the first quarter and a Canadian dollar which strengthened.
For the three and six months Three Months Six Months
ending June 30 ——————— ———————–
($000’s except where noted) 2003 2002 Change 2003 2002 Change
Revenues $ 17,900 $ 17,811 0% $ 38,335 $ 29,785 29%
Cash flow from operations $ 9,610 $ 9,103 6% $ 19,989 $ 15,507 29%
Basic cash flow
per share $ 0.46 $ 0.46 0% $ 0.97 $ 0.84 15%
Diluted cash flow
per share $ 0.46 $ 0.45 2% $ 0.95 $ 0.82 16%
Net earnings $ 2,003 $ 2,113 (5%) $ 4,208 $ 3,907 8%
Basic net earnings
per share $ 0.10 $ 0.11 (9%) $ 0.20 $ 0.21 (5%)
Diluted net earnings
per share $ 0.10 $ 0.10 0% $ 0.20 $ 0.21 (5%)
Net Capital expenditures –
acquisitions $ 2,248 $ 51,098 (96%) $ 12,524 $ 59,148 (79%)
Net Capital expenditures –
acquisitions $ 2,248 $ 9,122 (75%) $ 12,524 $ 17,172 (27%)
Bank debt including
working capital deficit $ 45,005 $ 52,262 (14%) $ 45,005 $ 52,262 (14%)
Average basic shares
outstanding 20,696 19,713 5% 20,682 18,437 12%
Average diluted shares
outstanding 21,082 20,147 5% 21,079 18,839 12%
Basic shares outstanding 20,714 20,611 0% 20,714 20,611 0%
For the three and six months ending June 30 Three Months
($000’s except where noted) 2003 2002 Change
– oil – barrels/day 5,335 5,060 5%
– gas sales – mmcfpd 1.784 3.716 (52%)
– total barrels of oil equivalent/day (6:1) 5,633 5,679 (1%)
– gross wells 3.0 7.0 (4.0)
– net wells 3.0 6.5 (3.5)
Netbacks ($/boe) except where noted
– oil ($/bbl) $ 34.74 $ 36.09 (4%)
– gas ($/mcf) $ 5.80 $ 3.56 63%
– wellhead $ 34.74 $ 34.48 1%
– hedge $ 0.18 $ (0.02) 1000%
– net realized $ 34.92 $ 34.46 1%
Royalty costs $ 7.30 $ 7.72 (5%)
Operating costs $ 4.89 $ 4.52 8%
Operating netback $ 22.73 $ 22.22 2%
General & Admin $ 1.92 $ 2.55 (25%)
Interest $ 1.14 $ 0.97 18%
Capital Taxes $ 0.92 $ 1.08 (15%)
Cash netback $ 18.75 $ 17.62 6%
For the three and six months ending June 30 Six Months
($000’s except where noted) 2003 2002 Change
– oil – barrels/day 5,328 4,675 14%
– gas sales – mmcfpd 1.801 2.459 (27%)
– total barrels of oil equivalent/day (6:1) 5,629 5,084 11%
– gross wells 21.0 20.0 1.0
– net wells 15.4 15.4 0.0
Netbacks ($/boe) except where noted
– oil ($/bbl) $ 39.86 $ 32.65 22%
– gas ($/mcf) $ 6.11 $ 3.38 81%
– wellhead $ 39.69 $ 31.65 25%
– hedge $ (2.06) $ 0.71 (391%)
– net realized $ 37.63 $ 32.36 16%
Royalty costs $ 8.34 $ 6.61 26%
Operating costs $ 5.15 $ 4.62 11%
Operating netback $ 24.14 $ 21.13 14%
General & Admin $ 2.20 $ 2.45 (10%)
Interest $ 1.13 $ 0.84 35%
Capital Taxes $ 1.19 $ 0.99 20%
Cash netback $ 19.62 $ 16.85 16%
In the second quarter, Upton earned $2.0 million and $0.10 basic per share. Cash flow from operations increased 6% to $9.6 million and $0.46 basic per share. WTI crude prices in 2003 averaged U.S. $28.90. These results are attributable to higher oil production and lower cash costs.
Revenues were static at $17.9 million in the second quarter and increased 29% for the first half of 2003 to $38.3 million, compared to $17.8 million and $29.8 million for the respective periods in 2002.
Higher revenues for the first half resulted from increased product prices and higher oil sales volumes, offset slightly by lower gas sales volumes. Year- to-date WTI oil prices averaged U.S. $31.34 per barrel compared to U.S. $23.97 per barrel. AECO gas prices averaged $7.45 per thousand cubic feet (mcf) compared to $3.82 per mcf resulting in net realized price increases of 16% to Cdn $37.63 per barrels of oil equivalent (boe) from Cdn $32.36 per boe. Higher WTI oil prices were tempered by hedging losses of $2.1 million ($2.06 per boe), all realized in the first quarter. Oil sales volumes increased 14% to 5,328 barrels of oil per day (bopd), compared to 4,675 bopd for the same period last year as a result of the increased production from the Empire acquisition in April 2002. Production in northwest Alberta resulted in a decrease in gas sales volumes to 1.8 million cubic feet per day (mmcfpd) compared to 2.5 mmcfpd for the first half of 2002.
Revenues remained static for the second quarter of 2003 compared to the second quarter of 2002, as higher WTI prices were offset by a strengthened Canadian dollar. Canadian dollar realized prices averaged $34.92 per boe for the first half of 2003 and $34.46 for the first half of 2002. WTI oil prices averaged U.S.$28.90 per barrel for the second quarter of 2003 compared to U.S.$26.26 per barrel for the second quarter of 2002, and AECO gas prices averaged $6.99 per mcf and $4.42 per mcf over the same respective periods. The 2003 second quarter U.S. exchange rate strengthened to 1.355. Oil sales volumes increased 5% to 5,335 bopd from 5,060 bopd, were offset by the 52% decrease in gas sales volumes to 1.8 mmcfpd compared to 3.7 mmcfpd as a result of production in northwest Alberta.
Royalties increased 40% to $8.5 million for the first half of 2003 compared to $6.1 million for the first half of 2002. In the second quarter of 2003 royalties decreased 6% to $3.7 million from $4.0 million in the second quarter of 2002, matching production and revenues over the same respective periods.
Higher production volumes increased operating costs to $5.3 million for the first half of 2003, compared to $4.2 million for the first half of 2002. Second quarter operating costs increased 7% to $2.5 million from $2.3 million.
General and administrative costs were $1.0 million for the second quarter of 2003 compared to $1.3 million for the second quarter of 2002. Year-to-date general and administrative costs were $2.2 million for the first half of 2003, compared to $2.3 million for the first half of 2002. Costs-to-date in 2003 are inclusive of employee retention accruals and higher corporate costs related to the process to maximize shareholder value compared to costs-to-date in 2002 which included additional employee options expense and consulting expense related to the Empire transition costs. On a per boe basis, general and administrative costs decreased 25% to $1.92 per boe in the second quarter of 2003 from $2.55 per boe in the second quarter of 2002.
Interest expense increased to $1.2 million for the first half of 2003, compared to $0.8 million for the first half of 2002 due to the higher debt levels carried following the Empire acquisition and increased interest rates of approximately 0.75%. Interest expense was $0.6 million for the second quarter of 2003 compared to $0.5 million for the second quarter of 2002. Debt levels dropped $7.5 million in the quarter and are expected to maintain interest costs below $600,000 per quarter barring any substantial change in interest rates.
Capital taxes were $1.2 million for the first half of 2003, compared to $0.9 million for the first half of 2002 tracking revenues realized from Saskatchewan properties. Capital taxes decreased 15% to $0.5 million in the second quarter of 2003, compared to $0.6 million for the second quarter of 2002. An increasing amount of production is subject to the reduced tax rate of 2.0% compared to the pre-November 2002 revenue tax rate of 3.6%.
Future tax expense was $2.5 million in the first half of 2003, compared to $1.7 million in the first half of 2002. The future tax rate is reduced as a result of federal tax rates for the resource industry, which were substantially enacted in the second quarter. Second quarter earnings had a positive impact of $700,000 from the enactment of these rate changes, but this was partially offset by adjustments to tax pools as a result of a federal tax audit.
Depletion and depreciation expense increased by 5% to $6.1 million in the second quarter of 2003 compared to $5.8 million for the second quarter of 2002 and 35% to $12.7 million for the first half of 2003 compared to $9.5 million for the first half of 2002. The depletion and depreciation rate was $12.51 per boe for the first half of 2003 compared to $10.27 per boe for the first half of 2002.
Capital expenditures were $12.5 million for the first half of 2003, compared to first half 2002 expenditures of $59.1 million which included the Empire acquisition. The capital expenditures of $12.5 million in 2003 included $2.2 million of second quarter costs primarily for the drilling of three north Midale wells. Substantially all expenditures were in southeast Saskatchewan.
Upton’s bank debt and working capital decreased to $45 million at June 30, 2003 from $52.8 million at December 31, 2002 and $52.5 million at March 31, 2003. This results in a bank debt and working capital to quarterly annualized cash flow ratio of 1.2 to 1.0. Bank lines were set at $50 million, down $5 million largely as a result of the change in the U.S./Cdn dollar exchange rate. Based on the company’s future plans, the new bank lines provide more than adequate liquidity.
In the second quarter, Upton produced 5,335 bopd and 1.8 mmcfpd for a total of 5,633 boepd. Production benefited from a busy first quarter drilling program. In the second quarter Upton drilled three horizontal wells in southeast Saskatchewan at a property purchased at the end of the first quarter on the northern edge of the Midale field. Two of these wells were brought on to production during the quarter, the third following the end of the quarter.
The first half drilling program included the drilling of 21 (15.4 net) wells, all in southeast Saskatchewan. In the second quarter, Upton began development of its north Midale property with the drilling of three successful horizontal wells. Capital expenditures were $2.2 million in the quarter and $12.5 million in the first six months down substantially from 2002, largely as a result of reduced expenditures in northwest Alberta.
Operating netbacks, before corporate costs and hedge losses, were $22.68 per boe in southeast Saskatchewan, $18.95 per boe in the U.S., and $28.12 per boe equivalent in northwest Alberta. Average overall operating net back per barrel was $22.55 per boe. The cash netback, after an $0.18 per barrel equivalent hedge gain, was $22.73 per boe equivalent.
Reserve changes during the quarter were positive. The three Midale wells drilled in the second quarter moved 0.3 million barrels of oil reserves to the proved producing category. New oil reserve additions, all in the proved undeveloped category, totaled 0.5 million barrels. These reserves were primarily a result of lease line well agreements negotiated in the second quarter in the Queensdale area of southeast Saskatchewan. The wells are scheduled for drilling in the third and fourth quarters.
The third quarter drilling schedule includes 10 (net 6.8) wells, 9 (5.8 net) development wells and 1.0 (1.0 net) exploratory wells. In southeast Saskatchewan Upton plans to drill eight wells, 7 (5.6 net) development wells and the one exploratory test. Upton hopes to add a second exploratory test late in the quarter. Upton recently received approval to drill at Tracy Mountain, North Dakota and will spud a Tyler sand well (0.475 net) in about three weeks. A Sulphur Point gas completion (0.75 net) on an existing Keg River suspended oil well in northwest Alberta is also planned for the third quarter.
In early June Upton confirmed the continuation of the process to maximize shareholder value. At that time a strategy designed to maximize Upton’s net asset value was put in place. In the second quarter, Upton was highly effective in this strategy as follows:
– Maintained production levels at first quarter rates.
– Negotiated lease line agreements at Queensdale, which added
0.5 million barrels of new southeast Saskatchewan light oil reserves.
– Produced 0.5 million barrels at prices of WTI U.S. $28.90, at higher
netbacks than independent reserve report.
– Invested $2.2 million of second quarter cash flow primarily to drill
three wells at north Midale, southeast Saskatchewan, a property
acquired in March 2003, to move reserves from proven undeveloped to
– Used $7.5 million in second quarter cash flow to reduce debt.
In the third quarter, the company plans to drill five of the six Queensdale wells, moving the new reserves to proved producing, one or two southeast Saskatchewan exploratory tests, one T
ler well at Tracy Mountain, North Dakota and one gas completion in northwest Alberta. All are lower risk, highly economic development work designed to add to the value of the company. Third quarter capital expenditures are forecast at $5 to $6 million and cash flow in excess of this amount will be used to further reduce debt.
As the process to maximize shareholder value continues Upton’s operating strategy will be to continue to strengthen its balance sheet while keeping production and reserve levels strong, all focused on enhancing net asset value.
The common shares of Upton are listed on the Toronto Stock Exchange under the symbol “URC”.
This information has been neither approved nor disapproved
by the Toronto Stock Exchange
For further information: Scott Dutton, President & C.E.O., Upton Resources Inc., (403) 218-6080; Phil Grubbe, V.P. Finance & C.F.O., Upton Resources Inc., (403) 218-8978, ; Andre St. Onge, Vice President, Exploration, Upton Resources Inc., (403) 218-6092; Website: www.uptonres.ca; E-Mail Address: email@example.com
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