Spinnaker Exploration Reports 109% Increase in 4Q Earnings
Spinnaker Exploration (NYSE: SKE) reported fourth quarter 2004 earnings of $13.5 million, or $0.39 per diluted share, on revenues of $70.1 million, representing an increase of 109% compared to fourth quarter 2003 earnings of $6.5 million, or $0.19 per diluted share, on revenues of $49.1 million. Net income in 2004 increased 47% to $53.9 million, or $1.55 per diluted share, compared to net income in 2003 of $36.6 million, or $1.08 per diluted share.
Production was 11.0 billion cubic feet of gas equivalent ("Bcfe") in the fourth quarter of 2004 compared to 11.5 Bcfe in fourth quarter of 2003 and 11.3 Bcfe in the third quarter of 2004. Production in the fourth quarter of 2004 included approximately 8.2 billion cubic feet of gas ("Bcf") and 464,000 barrels of oil ("BO"). Production in the fourth quarter of 2004 decreased 4% from the fourth quarter of 2003 and 2% from the third quarter of 2004 primarily due to normal production declines. Oil production in the fourth quarter of 2004 increased 27% from the third quarter of 2004 primarily due to first production (commencing December 4) from our deepwater project at Green Canyon 338/339/382 ("Front Runner"). The Company's net current producing capacity is approximately 125 million cubic feet of gas equivalent ("MMcfe") per day.
Cash from Operations
Cash from operations in the fourth quarter of 2004 increased 43% to $59.6 million compared to $41.7 million in the fourth quarter of 2003. Cash from operations in 2004 increased 22% to a record $232.3 million compared to $191.1 million in 2003. Cash from operations is a non-GAAP financial measure and is presented because of its acceptance as an indicator of the ability of an oil and gas exploration and production company to internally fund exploration and development activities. This measure should not be considered as an alternative to net cash provided by operating activities as defined by generally accepted accounting principles. A reconciliation of cash from operations to net cash provided by operating activities is shown below:
Three Months Ended Year Ended December 31, December 31, 2004 2003 2004 2003 Net cash provided by operating activities $60,956 $31,603 $219,732 $198,110 Changes in operating assets and liabilities (1,397) 10,062 12,557 (7,041) Cash from operations $59,559 $41,665 $232,289 $191,069Revenues
Revenues increased 43% in the fourth quarter of 2004 to $70.1 million compared to $49.1 million in the fourth quarter of 2003. Revenues increased 20% to a record $272.9 million in 2004 compared to $226.9 million in 2003. The increase in revenues in both the fourth quarter and full-year 2004 was primarily due to higher realized natural gas and oil prices (after the effects of hedging activities).
The average natural gas price increased approximately 38% and the average oil price increased approximately 52% in the fourth quarter of 2004 compared to the fourth quarter 2003. The average natural gas price increased approximately 8% and the average oil price increased approximately 29% in 2004 compared to 2003. The average sales prices per unit were as follows:
Three Months Ended Year Ended December 31, December 31, 2004 2003 2004 2003 Natural gas revenues from production (per Mcf) $6.37 $4.63 $5.92 $5.46 Effects of hedging activities (per Mcf) (0.33) (0.47) (0.19) (0.93) Average realized price (per Mcf) $6.04 $4.16 $5.73 $4.53 Oil and condensate revenues from production (per Bbl) $45.05 $29.57 $39.45 $30.56 Effects of hedging activities (per Bbl) (1.27) --- (0.39) --- Average realized price (per Bbl) $43.78 $29.57 $39.06 $30.56 Total revenues from production (per Mcfe) $6.66 $4.68 $6.07 $5.39 Effects of hedging activities (per Mcfe) (0.31) (0.38) (0.16) (0.77) Total average realized price (per Mcfe) $6.35 $4.30 $5.91 $4.62
The depreciation, depletion and amortization ("DD&A") rate was $3.43 per Mcfe in the fourth quarter of 2004 compared to $2.68 per Mcfe in the fourth quarter of 2003 and $3.17 per Mcfe in the third quarter of 2004. The DD&A rate increased 8% from the third quarter of 2004 primarily due to a net downward revision of oil and gas reserves of approximately 6.4 Bcfe, or 2% of oil and gas reserves as of the beginning of the quarter, and the cost of unsuccessful drilling activities in the fourth quarter of 2004.
General and administrative expenses increased approximately $1.0 million in the fourth quarter of 2004 compared to the fourth quarter of 2003 primarily due to higher employment-related expenses and the costs associated with the implementation of Sarbanes-Oxley Section 404.
Income tax and cash tax (actual cash paid for taxes) rates in 2004 were 36% and 0%, respectively.
Fourth quarter 2004 additions to property and equipment were $64.0 million and included lease acquisition and related costs of $3.0 million, exploration costs of $33.8 million, development costs of $27.1 million and other property and equipment costs of $0.1 million. Additions to property and equipment in 2004 were $265.7 million, including lease acquisition and related costs of $15.9 million, exploration costs of $150.1 million, development costs of $99.3 million and other property and equipment costs of $0.4 million. Dry hole costs, including associated leasehold costs, were approximately $24.9 million and $83.6 million in the fourth quarter and the year ended December 31, 2004, respectively.
The Company recorded $11.8 million in other assets as of December 31, 2004 in connection with its previously-disclosed international opportunity. This amount relates to Spinnaker's share of incurred costs as of December 31, 2004 and paid to the operator subsequent to year-end in order to execute the Farmout Agreement. If the Company does not receive local governmental approval, the amount will be reimbursed.
Seismic Data and Related Costs
The Company received a comment letter dated December 27, 2004 from the staff of the Securities and Exchange Commission ("SEC") based upon a review of the Company's Form 10-K for the year ended December 31, 2003. The Sarbanes- Oxley Act of 2002 mandates that the staff review the Company's periodic reports not less than every three years for public companies. The staff's comments related to the Company's methodology for the classification and transfer of seismic data and other seismic-related costs to the full cost amortization base. While the Company believed from the beginning that the review would not have a material impact on its financial statements, management felt it prudent to complete its discussions with the SEC before issuing this earnings release. The discussions resulted in the Company reclassifying $2.5 million of costs from evaluated properties to unevaluated properties, all within the net property and equipment balance of $1.061 billion at year-end 2004.
Since October 28, 2004, Spinnaker has participated in four successful wells in seven attempts. A summary of successful wells follows:
Working Net Revenue Well Interest (WI) Interest (NRI) Operator DeSoto Canyon 618 #2 (San Jacinto) 27% 23% Dominion Galveston 210 #1 67% 56% Spinnaker Ship Shoal 159 #1 15% 13% Tana Vermilion 287 #A-13 20% 14% PetroQuest Spinnaker has participated in 104 successful wells in 176 attempts since inception (59% gross/60% net).
The Company's outside reserve engineers, Ryder Scott Company, L.P., estimated proved oil and gas reserves net to the Company's interest to be 306.7 Bcfe at December 31, 2004. The reserve total is comprised of 146.6 Bcf and 26.7 million BO (MMBO). Proved reserve additions in 2004 were 40.8 Bcfe. The Company had net downward revisions of 20.4 Bcfe in 2004, of which 14.3 Bcfe was announced with the mid-year reserve report and related to the retraction of royalty suspension volumes associated with Front Runner. Should future annual oil and gas prices fall below the thresholds calculated by the Minerals Management Service, the royalty suspension volumes that remain to be recovered would be reinstated to the benefit of Spinnaker's interest. The present value of future net cash flows (before income taxes) discounted at 10% and using prices in effect at year-end is estimated to be approximately $1.0 billion.
The Company is currently involved in seven rig operations. Three of the operations are located on the shelf and three are located in deep water. The Company currently has one international operation ongoing subject to foreign government approval of its transfer of interest. Three of the operations are operated by Spinnaker. Five of the operations are exploratory, one is development and one is a completion.
Various activities are ongoing in several field areas in which the Company owns interests. The following summary information updates the Company's progress on many of these projects:
Eastern Gulf of Mexico
Spiderman Development (DeSoto Canyon 620/621)
The Spiderman development plan is complete. The field will be developed via subsea tieback to Independence Hub, a Floating Production Facility ("FPF") located in Mississippi Canyon 920. The FPF construction has commenced in Singapore and equipment has been ordered for the export pipelines and subsea tiebacks. The FPF will be capable of processing 850 million cubic feet of gas per day. Spinnaker owns 10.6% of the processing rights associated with the facility and export pipelines. The Company anticipates first production during 2007.
Spinnaker owns an 18% WI and 16% NRI (or 18% NRI if eligible for royalty suspension) in the Spiderman field.
San Jacinto Development (DeSoto Canyon 618/619)
The San Jacinto development plan has advanced substantially. It will be jointly developed with Spiderman via subsea tieback to the Independence Hub. An additional exploratory/delineation well has been drilled and was successful, finding a total of 110 feet of high quality Middle Miocene pay. A third well could be drilled prior to installation of the FPF.
Spinnaker owns a 27% WI and 23% NRI (or 27% NRI if eligible for royalty suspension) in the San Jacinto field.
Front Runner/Front Runner South/Quatrain Field Development (Green Canyon
First production from the Front Runner spar occurred on December 4, 2004 from the Green Canyon 339 #A-6 well. The #A-6 well is currently producing approximately 15,500 barrels of oil equivalent per day ("BOEPD"). The #A-1 well has now been completed and has commenced the testing and ramp-up process. It is anticipated that the #A-1 well will produce 12,000 to 15,000 BOEPD following the ramp-up.
Spinnaker owns a 25% WI and 22% NRI (or 25% NRI if eligible for royalty suspension) in the Front Runner project.
Seventeen Hands Development (Mississippi Canyon 299)
Gas was discovered in the MC 299 #1 well by Spinnaker and its partners in April 2001 in water approximately 5,880 feet deep. The field is now being developed jointly with a nearby gas discovery. Both discoveries are subsea tiebacks to an existing host platform. Recently, an additional sidetrack of the Seventeen Hands discovery well has been successful. The well has encountered high quality Miocene pay in a structurally-favorable position. The well will ultimately be completed and hooked up in the second half of 2005 with first production to follow shortly thereafter.
Spinnaker owns a 25% WI and 22% NRI in the field.
Thunder Hawk (Mississippi Canyon 734)
The MC 734 #2 well is currently drilling to explore and delineate the western portion of the discovery and to test the deeper portion of the prospective Miocene section. Several development options are currently under consideration. Spinnaker has not booked reserves associated with this discovery as of year-end.
Spinnaker owns a 25% WI and 22% NRI (or 25% NRI if eligible for royalty suspension) in the Thunder Hawk discovery.
Minuteman Development (Eugene Island 213 #1)
The EI 213 #1 well was successfully completed and tested. Final hook-up is complete and the well has commenced production at a rate of approximately 17 million cubic feet of gas equivalent per day with a flowing tubing pressure of 14,580 pounds per square inch.
Spinnaker operates the Minuteman discovery and owns a 33% WI in the field. Spinnaker's NRI in the field will be 33% until 25 Bcf gross is produced and 28% thereafter as EI 213 is eligible for royalty relief, subject to pricing thresholds.
Bases Loaded Prospect (Galveston 210 #1)
Gas was discovered at Galveston 210. The well was completed and tested. A caisson has been over-driven and a caisson deck will be installed and the well will be tied back to a local host facility. First production is anticipated in the second quarter of 2005.
Spinnaker operates the well and owns a 67% WI and 56% NRI in the block.
Ship Shoal 159 Prospect
A successful gas well was drilled and completed in Ship Shoal 159. A caisson was over-driven and a caisson deck will be installed and the well will be tied back to a partner-owned local host facility. First production is anticipated in the first quarter of 2005.
Spinnaker owns a 15% WI and 13% NRI in the block.
Jambalaya Prospect (Vermilion 287 #A-13)
A successful oil well was drilled and completed in Vermilion Block 287. This well was drilled from an existing structure with full processing capabilities. Minor upgrades to the system are currently in progress and first production is expected in the first quarter of 2005.
Spinnaker owns a 20% WI and a 14% NRI in the well.
Guidance Actual Actual Year Guidance Guidance Q4 2004 2004 Q1 2005 Year 2005 Income Statement Parameters: Avg Daily Production (MMcfe/day) 120 126 122 137-151 % Gas 75% 77% 70% 60% Avg Daily Hedged Gas Volumes (Bbtus/day) - Swaps 8.4 27.1 20.0 10.8 Avg Price - Swaps $4.92 $5.47 $7.76 $7.03 Avg Daily Hedged Gas Volumes (Bbtus/day) - Collars 18.4 19.6 --- --- Avg Ceiling Price - Collars $6.56 $6.03 --- --- Avg Floor Price- Collars $4.73 $4.68 --- --- Avg Daily Hedged Oil Volumes (MBbls/day) - Swaps 1.0 0.3 1.0 1.0 Avg Price - Swaps $42.86 $42.86 $42.12 $40.34 Avg Daily Hedged Oil Volumes (MBbls/day) - Collars 1.0 0.3 3.0 3.0 Avg Ceiling Price - Collars $50.25 $50.25 $44.73 $44.73 Avg Floor Price - Collars $40.00 $40.00 $38.67 $38.67 G&A (in millions)* $3.8 $15.8 $4.1 $16.5 Interest Expense, Net (in millions) $0.3 $1.2 $1.6 $7.3 Capitalized Interest (in millions) $1.0 $2.9 $1.2 $2.5 Accretion Expense (in millions) $0.9 $3.1 $0.9 $4.0 Avg Cash Income Tax Rate 0% 0% 0% 1% Avg Accrual Income Tax Rate 33% 36% 36% 36% Weighted Average Shares Outstanding - Diluted (in millions) 34.9 34.8 35.0 35.5 Avg LOE, Workover & Severance Taxes / Mcfe $0.61 $0.53 $0.68 $0.61 Avg DD&A / Mcfe $3.43 $3.09 $3.50 $3.50 Spending Parameters: Shelf Wells Drilled: Gross Wells 7 15 2 10 Net Wells 2.4 6.1 1.4 4.9 Deepwater Wells Drilled: Gross Wells 3 12 1 11 Net Wells 0.6 2.7 0.2 3.1 Total Wells Drilled: Gross Wells 10 27 3 21 Net Wells 3.0 8.8 1.6 8.0 Capital Expenditures (in millions): $64 $266 $80 $280 Leasehold Acquisition $3 $16 $20 $45 Exploration $34 $150 $53 $190 Development $27 $100 $7 $45 *The Company will provide guidance on the impact of expensing stock options beginning July 1, 2005 in connection with its first quarter 2005 release.
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