Stone Energy Announces Third Quarter 2004 Results
|Thursday, November 04, 2004
Stone Energy Corporation (NYSE: SGY) announced a 12% increase in net income, which totaled $25.6 million, or $0.95 per share, on oil and gas revenue of $128.3 million for the third quarter of 2004, compared to net income of $22.8 million, or $0.86 per share, on oil and gas revenue of $116.0 million for the third quarter of 2003. For the nine months ended September 30, 2004, net income totaled $97.2 million, or $3.62 per share, on revenue of $404.1 million compared to net income of $107.3 million, or $4.04 per share, on revenue of $390.8 million during the comparable 2003 period. All per share amounts are on a diluted basis.
As previously announced, shut-ins for Hurricane Ivan resulted in the deferral of September production volumes from the Gulf of Mexico approximating 1.7 billion cubic feet of natural gas equivalent. Certain fields in the Main Pass and Mississippi Canyon areas remain shut-in due to hurricane damage to non-operated wells and platforms, as well as downstream production facilities and pipelines owned by third parties, which has impacted Stone's ability to restore production at these fields. Currently, Stone has eight Gulf of Mexico properties curtailed or shut-in from Hurricane Ivan representing net daily production of approximately 62 million cubic feet of natural gas equivalent (MMcfe). Stone expects production from these fields to return beginning in the first quarter of 2005. The Company is exploring ways to hasten the return of production including associated gas re-injection and pipeline rerouting.
Net daily production volumes during the third quarter of 2004 averaged approximately 229 MMcfe, or 11% less that the average daily production of 256 MMcfe produced during the third quarter of 2003. The decline in third quarter 2004 production volumes was due to the combined impact of shut-ins for rig mobilizations and Hurricane Ivan. For the fourth quarter of 2004, Stone expects net daily production to average between 180-200 MMcfe. This estimate assumes no contribution from the wells shut-in as a result of Hurricane Ivan.
Prices realized during the third quarter of 2004 averaged $41.79 per barrel (Bbl) of oil and $5.54 per thousand cubic feet (Mcf) of natural gas, which represents a 24% increase, on a Mcfe basis, over third quarter 2003 average realized prices of $29.36 per Bbl of oil and $4.93 per Mcf of natural gas. Average realized prices during the first nine months of 2004 were $37.62 per Bbl of oil and $5.63 per Mcf of natural gas compared to $30.43 per Bbl of oil and $5.57 per Mcf of natural gas realized during the first nine months of 2003. All unit pricing amounts include the cash settlement of hedging contracts.
During the third quarter of 2004, discretionary cash flow increased 7% to $88.1 million compared to $82.7 million generated during the third quarter of 2003. Net cash flow provided by operating activities, as defined by generally accepted accounting principles (GAAP), totaled $111.6 million and $98.4 million during the three months ended September 30, 2004 and 2003, respectively. For the first nine months of 2004, discretionary cash flow totaled $301.1 million compared to $301.3 million during the first nine months of 2003. Net cash flow provided by operating activities totaled $299.9 million and $311.5 million during the nine months ended September 30, 2004 and 2003, respectively. (Please see "Non-GAAP Financial Measure" below.)
Normal lease operating expenses incurred during the third quarter of 2004 totaled $19.7 million compared to $15.1 million for the comparable quarter in 2003. For the nine months ended September 30, 2004 and 2003, normal lease operating expenses were $53.5 million and $45.8 million, respectively. The increase in normal lease operating expenses during 2004 is the combined result of an increase in the number of active offshore properties, higher oil production volumes during 2004, which are more costly to produce as compared to natural gas, the extra costs associated with storm-related shut-ins and evacuations and increases in overall service costs over 2003.
Major maintenance expenses, which represent major repair and maintenance costs that vary from period to period, totaled $11.1 million during the third quarter of 2004 compared to $5.2 million in the third quarter of 2003. Third quarter 2004 major maintenance expenses consisted primarily of replacement wells at Lafitte and Vermilion Block 131, a tubing replacement at West Delta Block 98 and a pipeline repair at East Cameron Block 64. Stone expects fourth quarter 2004 major maintenance expenses to decrease approximately 25% over third quarter 2004 major maintenance expenses based upon planned operations.
Depreciation, depletion and amortization (DD&A) expense on oil and gas properties totaled $45.5 million for the third quarter of 2004, compared to $41.3 million during the third quarter of 2003. DD&A expense on oil and gas properties for the nine months ended September 30, 2004 totaled $140.9 million compared to $122.6 million during the same year-to-date period of 2003. The increase in DD&A on a unit basis during 2004 is the result of higher per unit costs of oil and gas property acquisitions and increases in per unit full-cycle cost of finding and developing proved reserves and the impact of drilling results.
Capital expenditures related to oil and gas properties during the third quarter of 2004 totaled $81.7 million, including $18.6 million of acquisition costs (includes promoted drilling costs), $4.0 million of capitalized salaries, general and administrative expenses and $1.7 million of capitalized interest. Year-to-date 2004 additions to oil and gas property costs of $283.8 million include $68.1 million of acquisition costs (includes promoted drilling costs), $11.9 million of capitalized salaries, general and administrative expenses and $5.0 million of capitalized interest. These investments were financed with cash flow from operating activities, working capital and bank borrowings.
During the third quarter of 2004 Stone evaluated 10 new wells, seven of which were productive. Through November 2, 2004, Stone has spud 48 of the 55 wells planned for 2004. The Gulf Coast Basin onshore and offshore shelf including Deep Shelf tests comprise approximately 85% of 2004 capital expenditures budget and 27 exploratory and 13 development wells. Deep water operations for 2004 include two exploratory wells representing approximately 6% of our 2004 capital budget. The remainder of capital expenditures is in the Rocky Mountains consisting of 13 wells, or approximately 9% of 2004 capital budget. The following is an update of certain ongoing or recently completed operations:
Gulf of Mexico - Shelf
Main Pass Block 288. The final well planned from the "A" platform this year, the No. A-7 STK1 Well, was drilled to a total measured depth (MD) of 10,366 feet to test the Sam Adams Prospect and encountered 50 net feet of oil pay. Although not at its expected full flowing potential, the well flowed at an initial test rate of 400 barrels of oil and 340 Mcf of natural gas prior to being shut-in in preparation for Hurricane Ivan. In addition, Stone recompleted the No. A-21 STK Well into the Upper M, but was unable to get a test rate prior to the Hurricane Ivan evacuation. Stone has a 100% working interest (WI) and 83.3% net revenue interest (NRI) in these wells.
Both wells were shut in for Hurricane Ivan in mid-September along with the remainder of the wells on the "A" platforms on Main Pass Blocks 288 and 287. Extensive damage occurred to a large gas pipeline leaving the Main Pass 289 "B" platform, through which production flows. Stone has completed most of the Main Pass Block 288 "A" platform upgrades to handle increased productive capacity from the existing wells, but has placed construction of a new gas pipeline from the platform on hold pending repairs to the Main Pass Block 289 "B" platform and the damaged gas pipeline.
Viosca Knoll Block 773. Stone has begun a four-well drilling program on Viosca Knoll Block 773 from an open water location to test multiple fault blocks for possible pay accumulations and the extent of those accumulations. The No. 1 Well to test the Cleveland Prospect was drilled to a total depth of 5,567 feet MD and logged oil pay in four sands. A second well in the program is currently drilling to a total depth of 9,224 feet (MD). Viosca Knoll Blocks 772, 773 and 774 were acquired by Stone during the 2004 OCS Lease Sale 190. Stone has a 100% working interest in these wells which are located southwest of and contiguous to Stone's Main Pass Block 288 Field.
Viosca Knoll Block 817. Stone has entered into an agreement with the owner of Viosca Knoll Blocks 817 and 861 to utilize an existing platform as a host structure from which to drill at least two wells and earn an interest in these blocks. The first well, the No. A-1 STK, to test the Antelope Prospect is currently drilling at 10,376 feet MD (7,614 feet TVD) and has logged 68 feet MD (37 feet of true vertical thickness (TVT)) of pay in the F4 sand with no water level. The F4 sand is the main field pay having produced more than 90 Bcf of gas in a separate fault block. The well is planned to 15,351 feet MD (12,145 feet TVD) to test deep, amplitude supported upper Miocene objectives. Viosca Knoll Blocks 817 and 861 are southwest of Main Pass Block 288 and contiguous to Viosca Knoll 773. Stone has a 100% WI in these earning wells.
East Cameron Block 265. The No. 5 Well on East Cameron Block 265 drilled from an open water location to a total depth of 4,500 feet MD in August 2004 and found 26 feet TVT of gas pay in four sands. This well established the western limits of the nine reservoirs in the No. 4 discovery well of the Donut Prospect. The decision was made to plug and abandon the No. 5 Well and use the No. 4 Well as the surface location for development of the Donut Prospect. Design and construction of a six-slot tripod structure has begun and installation of the structure is expected in the first quarter of 2005. Stone has a 50% WI and 40.7% NRI in these wells.
The Stone-operated No. 6 Well on the Kolache Prospect on East Cameron Block 265 was also drilled from an open water location to a total depth of 4,456 feet MD (4,000 feet TVD) in August 2004 in a fault block adjacent to the Donut Prospect and found non-commercial gas pay in seven sands. The well was plugged and abandoned. Stone has a 100% WI in the Kolache project.
South Marsh Island Block 192. The No. A-2 Well, the initial test of the Magic Prospect, reached a total depth of 16,144 feet MD (13,700 feet TVD) in August 2004 and logged 124 net feet (98 feet TVT) of pay before incurring mechanical difficulties. At this time, the turnkey drilling contractor is performing certain operations on the well in preparation of turning over operations to Stone. Upon completion, Stone will have a 50% WI in this well.
South Timbalier Blocks 143 and 166. Stone has exercised its preferential right to acquire additional working interests in South Timbalier Blocks 143, 164, 165, 166 and 171 for approximately $125 million, pending the execution of an Asset Purchase Agreement. After completion of the acquisition, Stone will hold a majority working interest in the blocks. Stone estimates that the wells applicable to these working interests are currently flowing at an average net daily rate of approximately 57 MMcfe. Stone expects to close this acquisition late in the fourth quarter of 2004 and intends to finance this acquisition with available cash and borrowings under its bank credit facility.
Gulf of Mexico - Deep Water
Mississippi Canyon Blocks 24. As previously announced, Stone has begun a deep water and deep shelf exploration venture with Kerr-McGee. The first well, a test of the Essex Prospect on Mississippi Canyon Block 24 was spud on October 13, 2004, with Kerr-McGee as the operator. The well is planned to a total depth of 18,000 feet TVD. The well is a test offsetting the Pompano field development. The well is currently drilling at approximately 8,778 feet. Stone has a 35% WI in this well. Kerr-McGee is the operator of the well with a 65% WI.
Pinedale Anticline, Wyoming. Stone's drilling program on the Pinedale Anticline in the Greater Green River Basin continues and has yielded six successful wells in 2004. During the third quarter, two wells were drilled and evaluated, both of which are completing. Four additional wells are planned for 2004. One of the wells, the Rainbow No. 13-27, is being drilled at a location more than 500 feet structurally lower than the crest of the Anticline as the initial test of the Southeast Pinedale Federal Unit. Stone has a non-operated 25% WI and 20% NRI in the Southeast Pinedale Unit. Stone has a 50% WI and a 41% NRI in the remainder of the Pinedale wells scheduled for this year and is the operator of the drilling portion of those wells.
Howard Ranch. In the Wind River Basin of central Wyoming, the field recording phase of the 70 square mile Howard Ranch 3D seismic survey ended September 30th. Processing is underway and should be complete in late December. Interpretation will follow with plans to have locations selected and drilling commenced in the second quarter of 2005. The Antelope Mesa Federal No. 1-14 Well reached a depth of 13,600 feet in early October and completion operations are underway. Stone has a 75% WI and 60% NRI in this well.
Non-GAAP Financial Measure
In this press release, Stone refers to a non-GAAP financial measure we call "discretionary cash flow." Management believes this measure is a financial indicator of our company's ability to internally fund capital expenditures and service debt. Management also believes 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. See reconciliation of discretionary cash flow to cash flow provided by operating activities in the Consolidated Statement of Operations and Net Cash Flow Information.