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NEWS RELEASE
SOUTHWESTERN ENERGY ANNOUNCES RECORD
2005 FINANCIAL AND OPERATING RESULTS
Net Income Increases by 43% to $147.8 Million
Proved Reserves Increase by 28% to 826.8 Bcfe
Houston, Texas – February 28, 2006...Southwestern Energy Company (NYSE: SWN) today announced financial and operating results for the fourth quarter and the year ended December 31, 2005. Calendar year 2005 highlights include:
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Record earnings of $147.8 million, up 43% from 2004
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Record net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure reconciled below) of $321.8 million, up 35% from 2004
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Record oil and gas production of 61.0 Bcfe, up 13% over 2004
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Record proved oil and gas reserves of 826.8 Bcfe, up 28% over 2004
For the fourth quarter of 2005, Southwestern reported net income of $48.9 million, or $0.29 per diluted share, up 48% from $32.9 million, or $0.22* per diluted share, for the same period in 2004. Net cash provided by operating activities before changes in operating assets and liabilities (non-GAAP; see reconciliation below), was $102.8 million in the fourth quarter of 2005, up 42% from $72.4 million in 2004. Strong commodity prices and higher production from the company’s exploration and production (E&P) segment led to the improved financial results.
Southwestern reported record net income for 2005 of $147.8 million, or $0.95 per diluted share, up from $103.6 million, or $0.70* per diluted share in 2004. Net cash provided by operating activities before changes in operating assets and liabilities (non-GAAP; see reconciliation below) also set a new record at $321.8 million, up from $237.7 million in 2004. A 13% increase in production volumes and higher realized natural gas and oil prices primarily drove the improved financial results.
“2005 was an outstanding year for our company, marked by record achievements in our operating and financial results,” stated Harold M. Korell, President and Chief Executive Officer of Southwestern Energy. “For the third straight year we set new records for annual production volumes and reserve replacement. Our financial results were also outstanding, as we delivered new records for earnings and cash flow, and our balance sheet is the strongest it’s ever been. We have started the year at a very fast pace and look forward to what 2006 will bring as results from our Fayetteville Shale play unfold.”
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* Adjusted to reflect the company’s two two-for-one stock splits during 2005.
Fourth Quarter of 2005 Financial Results
E&P Segment - Operating income from the company’s E&P segment was $69.6 million for the three months ended December 31, 2005, up from $50.6 million for the same period in 2004. The increase in 2005 was primarily due to increased production volumes and higher realized natural gas and oil prices, partially offset by increased operating costs and expenses.
Gas and oil production totaled 15.7 Bcfe for the three months ended December 31, 2005, up 4% compared to 15.1 Bcfe in the fourth quarter of 2004. The increase in 2005 production resulted primarily from increased production from our Overton Field in East Texas and the Arkoma Basin. Production during the fourth quarter of 2005 was lower than expected primarily due to delays in the company’s drilling programs in its Fayetteville Shale play and Ranger Anticline area in Arkansas caused by drilling rig problems. Southwestern’s first quarter 2006 production guidance is 15.7 to 16.1 Bcfe.
Southwestern’s average realized gas price was $7.51 per Mcf, including the effect of hedges, in the fourth quarter of 2005 compared to $5.58 per Mcf in the fourth quarter of 2004. The company’s commodity hedging activities lowered its average gas price $3.02 per Mcf during the fourth quarter of 2005 and $0.88 per Mcf during the same period in 2004. Disregarding the impact of the company’s hedges, the company’s average price received for its gas production during the fourth quarter of 2005 was approximately $2.44 per Mcf lower than average NYMEX spot prices, compared to approximately $0.65 per Mcf during the fourth quarter of 2004. This change was primarily due to widening locational market differentials that occurred in the company’s core operating areas during the fourth quarter of 2005.
Southwestern’s average realized oil price was $43.71 per barrel, including the effect of hedges, during the fourth quarter of 2005 compared to $37.00 per barrel in the fourth quarter of 2004. The company’s hedging activities lowered its average oil price $14.07 per barrel during the fourth quarter of 2005 and $10.56 per barrel during the same period in 2004.
Lease operating expenses per Mcfe for the company’s E&P segment were $0.51 per Mcfe in the fourth quarter of 2005, compared to $0.37 per Mcfe in the same period in 2004. The increase in lease operating expenses per Mcfe in 2005 resulted from increases in compression, saltwater disposal and gas processing costs as wells as generally higher oilfield service costs. General and administrative expenses per Mcfe were $0.64 during the fourth quarter of 2005, as compared with $0.39 for the same period in 2004. The increase in general and administrative expenses for the E&P segment was due primarily to increased payroll costs due to the expansion of the company’s E&P operations related to the Fayetteville Shale play and increased incentive compensation costs. Taxes other than income taxes per Mcfe were $0.40 during the fourth quarter of 2005, compared to $0.33 per Mcfe during the same period in 2004. The increase in 2005 was due primarily to increased severance and ad valorem taxes that resulted from increases in commodity prices. The company’s full cost pool amortization rate increased to $1.54 per Mcfe in the fourth quarter of 2005, compared to $1.23 per Mcfe for the same period in 2004, primarily due to increased finding and development costs.
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Natural Gas Distribution Segment - Operating income for the company’s natural gas distribution segment was $3.0 million for the three months ended December 31, 2005, down from $3.8 million for the same period in 2004. The decrease in operating income for this segment resulted from increased operating costs and expenses and reduced usage per customer due to customer conservation brought about by high gas prices and warmer than normal weather. Effective October 31, 2005, the Arkansas Public Service Commission approved a rate increase for Arkansas Western Gas Company of $4.6 million annually.
Midstream Services- Operating income for the company’s midstream services segment, which is comprised of natural gas marketing and gathering activities, was $2.2 million for the three months ended December 31, 2005, compared to $0.7 million in the same period in 2004. The increase in 2005 was primarily due to higher marketing margins on natural gas sales caused in large part by the increased volatility of locational market differentials in the company’s core operating areas.
Transportation and Other -The company recorded pre-tax income from operations relating to the company’s 25% interest in the Ozark Gas Transmission System of $1.3 million during the fourth quarter of 2005, compared to pre-tax income of $0.7 million for the same period in 2004.
Full-Year 2005 Financial Results
E&P Segment - Operating income from the company’s E&P segment was $234.8 million in 2005, up from $164.6 million in 2004. The increase in operating income in 2005 was due to increased production volumes and higher realized prices, partially offset by increased operating costs and expenses. Revenues for 2005 and 2004 also included pre-tax gains of $3.1 million and $4.5 million, respectively, related to the sale of gas in storage inventory.
Gas and oil production totaled 61.0 Bcfe in 2005, up 13% from 54.1 Bcfe in 2004. The increase in 2005 production resulted from a 5.4 Bcfe increase in production from the Overton Field in East Texas and a 1.9 Bcfe increase from the Arkoma Basin, primarily related to the Fayetteville Shale play. Production during 2005 was reduced by the effect of the curtailment of a portion of the company’s Overton Field production due to repairs of a non-operated transmission line and by the effect of Hurricane Katrina. Combined, these events reduced the company’s production by approximately 1.0 Bcfe. Southwestern’s 2006 oil and gas production guidance is 74.0 to 76.0 Bcfe, an increase of 21% to 25% over its 2005 production.
Southwestern’s average realized gas price was $6.51 per Mcf in 2005 compared to $5.21 per Mcf in 2004, including the effects of hedges. The company’s commodity hedging activities lowered its average gas price $1.22 per Mcf in 2005 and $0.59 per Mcf in 2004. Disregarding the impact of commodity price hedges, the average price received for the company’s gas production during 2005 was approximately $0.90 per Mcf lower than average NYMEX spot prices, compared to approximately $0.34 per Mcf during 2004. This change was primarily due to widening locational market differentials that occurred during 2005. Assuming a NYMEX commodity price for 2006 of $8.00 per Mcf of gas, the company expects its differential for the average price received for its gas production to be approximately $0.60 to $0.70 per Mcf below the NYMEX Henry Hub index price, including the impact of its basis hedges. Within this guidance, Southwestern is currently estimating
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that its market differentials for the first quarter of 2006 will be in the range of $0.70 to $0.80 per Mcf.
Southwestern’s average oil price was $42.62 per barrel in 2005, compared to $31.47 per barrel in 2004, including the effects of hedges. The company’s hedging activities lowered its average oil price $11.75 per barrel in 2005 and $9.08 per barrel in 2004. Disregarding the impact of hedges and based on the current price environment, the company expects the average price received for its oil production during 2006 to be approximately $1.50 per barrel lower than average spot market prices, as market differentials reduce the average prices received.
Lease operating expenses per Mcfe for the company’s E&P segment were $0.48 per Mcfe in 2005, compared to $0.38 per Mcfe in 2004. Lease operating expenses per unit of production increased in 2005 due primarily to increases in compression, saltwater disposal and gas processing costs as well as generally higher oilfield service costs. Taxes other than income taxes per Mcfe were $0.37 in 2005, compared to $0.28 per Mcfe in 2004. The increase in 2005 was primarily due to increased severance and ad valorem taxes that resulted from increases in commodity prices.
General and administrative expenses per Mcfe were $0.46 in 2005, compared to $0.36 in 2004. The increase in general and administrative costs per Mcfe in 2005 from 2004 was due primarily to increased payroll costs due to the expansion of the company’s E&P operations related to the Fayetteville Shale play and increased incentive compensation costs. The number of employees in the company’s E&P segment increased to 280 at December 31, 2005, up from 147 at December 31, 2004. The company’s full cost pool amortization rate increased to $1.42 per Mcfe in 2005, up from $1.20 per Mcfe in 2004, primarily due to increased finding and development costs.
Natural Gas Distribution Segment - Operating income for the company’s natural gas distribution segment was $4.9 million for the year ended December 31, 2005, compared to $8.5 million in 2004. The decrease in 2005 operating income for this segment resulted primarily from increased operating costs and expenses and reduced usage per customer due to customer conservation brought about by high gas prices and warmer than normal weather. Weather during 2005 in the utility's service territory was 9% warmer than normal and 1% colder than the prior year. Effective October 31, 2005, the Arkansas Public Service Commission approved a rate increase for Arkansas Western Gas Company of $4.6 million annually, exclusive of costs to be recovered under the utility’s purchase gas adjustment clause.
Midstream Services - Operating income for the company’s natural gas marketing and gathering activities was $5.7 million in 2005, compared to $3.2 million in 2004. Southwestern marketed 61.9 Bcf of gas in 2005, compared to 57.0 Bcf in 2004. The increase in 2005 operating income was primarily due to higher marketing margins on natural gas sales caused in large part by the increased volatility of locational market differentials in the company’s core operating areas. The increase in volumes marketed in 2005 resulted from marketing the company’s increased production volumes, largely related to its Overton Field in East Texas. Of the total volumes marketed, production from the company’s exploration and production subsidiaries accounted for 76% in 2005 and 77% in 2004.
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Midstream services also had gathering revenues of $1.0 million in 2005 related to gathering systems it owns in Arkansas. Gathering revenues for this segment are expected to continue to grow in the future as gathering systems for the company’s Fayetteville Shale play are constructed to support the development of this play.
Transportation and Other -The company also recorded pre-tax income from operations related to its investment in the Ozark Gas Transmission System of $1.6 million in 2005, compared to a pre-tax loss of $0.4 million in 2004. These amounts are recorded in other income (expense) in the company’s income statement. The pre-tax income in 2005 results from an increase in volumes transported and higher transportation rates collected on those volumes.
In 2005, other revenues included a pre-tax gain of $0.4 million, compared to a pre-tax gain of $5.8 million in 2004, related to sales of undeveloped real estate and certain property and equipment.
Southwestern Reports Record Oil and Gas Reserves
Southwestern’s oil and gas reserves totaled 826.8 Bcfe at December 31, 2005, up 28% from 645.5 Bcfe at the end of 2004. During 2005, the company had extensions and discoveries of 274.7 Bcfe, production of 61.0 Bcfe, net dispositions of 0.8 Bcfe and net downward revisions of 31.7 Bcfe. The company’s reserve additions were primarily related to its successful drilling programs in East Texas and the Arkoma Basin, including 96.7 Bcf from the company’s Fayetteville Shale play. The downward reserve revisions during 2005 were primarily due to minor changes to decline rates for wells at the company’s Overton Field and further unexpected declines associated with the company’s Gulf Coast properties. The company’s reserve replacement ratio and average finding and development cost, including the effects of net downward reserve revisions but excluding capital invested in drilling rigs was 399% and $1.71 p er Mcfe, respectively, in 2005. This compares to 365% and $1.43, respectively, in 2004. For the period ending December 31, 2005, Southwestern’s three-year average reserve replacement ratio was 364%, and its estimated three-year average finding and development cost was $1.53 per Mcfe, including revisions and excluding the investment in drilling rigs.
Excluding the effects of revisions, the company’s reserve replacement ratio and estimated finding cost were 450% and $1.51 per Mcfe in 2005, compared to 388% and $1.34 per Mcfe, respectively, in 2004. For the period ending December 31, 2005, Southwestern’s three-year average reserve replacement ratio was 402%, and its estimated three-year average finding and development cost was $1.38 per Mcfe, excluding revisions and excluding the investment in drilling rigs.
Natural gas comprised 93% of Southwestern’s proved equivalent reserves at the end of 2005, and the company’s reserve life index at December 31, 2005 was approximately 13.6 years. Proved developed reserves accounted for approximately 73% of Southwestern’s total proved reserves at year-end 2005, compared to 83% at year-end 2004. Netherland, Sewell & Associates, Inc., an independent oil and gas reserve engineering firm, audited the company’s proved reserves at year-end 2005 and 2004.
At December 31, 2005, Southwestern's pre-tax PV-10 estimate of its oil and gas reserves was $1,986.4 million and its after-tax PV-10 value (standardized measure) was $1,420.8
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million, compared to a standardized measure of $892.3 million at year-end 2004. The company's standardized measure at year-end 2005 was calculated based upon quoted market prices of $10.08 per Mcf for Henry Hub gas and $61.04 per barrel for West Texas Intermediate oil, adjusted for market differentials.
The following table details additional informationrelating to reserve estimates as of and for the year ended December 31, 2005:
| | Natural Gas (Bcf) | Crude Oil (MMBbls) | Total (Bcfe) |
Proved Reserves, Beginning of Year | 594.5 | 8.5 | 645.5 |
Revisions of Previous Estimates | (30.0) | (0.3) | (31.7) |
Extensions, Discoveries, & Other Additions | 264.7 | 1.7 | 274.7 |
Production | (56.8) | (0.7) | (61.0) |
Acquisition of Reserves in Place | 0.0 | 0.0 | 0.0 |
Disposition of Reserves in Place | (0.1) | (0.1) | (0.7) |
Proved Reserves, End of Year | 772.3 | 9.1 | 826.8 |
Proved, Developed Reserves: | | | |
Beginning of Year | 491.7 | 7.8 | 538.3 |
End of Year | 551.5 | 8.3 | 601.3 |
The following table provides information as of December 31, 2005 related to proved reserves, well count, and net acreage, and 2005 annual information as to production and capital expenditures, for each of our core operating areas, for our New Ventures and overall:
| Arkoma | | | | | |
| | Fayetteville | East | | Gulf | New | |
| Conventional | Shale Play | Texas | Permian | Coast | Ventures | Total |
Estimated Proved Reserves: | | | | | | | |
Total Reserves (Bcfe) | 271.0 | 101.0 | 368.7 | 58.6 | 27.5 | - | 826.8 |
Percent of Total | 33% | 12% | 45% | 7% | 3% | - | 100% |
Percent Natural Gas | 100% | 100% | 96% | 38% | 90% | - | 93% |
Percent Proved Developed | 76% | 15% | 82% | 91% | 96% | - | 73% |
| | | | | | | |
Production (Bcfe) | 20.2 | 1.8 | 28.2 | 6.9 | 3.9 | - | 61.0 |
Capital Investments (millions) | $64.5 | $154.5(1) | $183.6 | $15.1 | $7.9 | $25.7(1) | $451.3 |
Total Gross Producing Wells | 952 | 54 | 283 | 410 | 57 | - | 1,756 |
| | | | | | | |
Total Net Acreage | 427,949(2) | 739,294 | 36,086 | 34,826 | 17,390 | 116,633 | 1,372,178 |
Net Undeveloped Acreage | 240,917(2) | 719,680 | 16,991 | 7,255 | 6,351 | 116,633 | 1,107,827 |
| | | | | | | | |
PV-10: | | | | | | | |
Pre-tax (millions) | $738.9 | $156.9 | $852.4 | $149.5 | $88.7 | - | $1,986.4 |
After-tax (millions) | $528.5 | $112.3 | $609.6 | $107.0 | $63.4 | - | $1,420.8 |
Percent of Total | 37% | 8% | 43% | 8% | 4% | - | 100% |
Percent Operated | 81% | 100% | 81% | 38% | 59% | - | 78% |
(1) Our Fayetteville Shale play capital investments include $35.1 million invested in drilling rigs and $40.7 million in leasehold acquisition costs. New Ventures capital investments include $4.4 million relating to two wells in the Angelina River Trend project that are now part of the company's East Texas program.
(2) Includes 123,442 net developed acres and 1,431 net undeveloped acres in the company's Conventional Arkoma Basin operating area that are also within the company's Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above.
2005 E&P Operations Review
Southwestern invested a total of $451.3 million in its E&P program during 2005, including $35.1 million in drilling rigs, and participated in drilling 247 wells. Of these drilled wells, 197 were successful, eight were dry and 42 were still in progress at year-end. Of the $451.3
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million invested in 2005, approximately $35.6 million was invested in exploratory drilling, $287.5 million in development drilling and workovers, $60.5 million for leasehold acquisition and seismic expenditures, $35.1 million for the purchase of drilling rigs and related equipment and $32.5 million in capitalized interest and expenses and other technology-related expenditures.
Conventional Arkoma Program - Southwestern participated in 71 wells in its conventional Arkoma Basin drilling program during 2005. Of the 71 wells, the company had 61 producers, five dry holes and five wells in progress at year-end, resulting in a 92% drilling success rate. Included in the 71 wells are 37 wells in which the company participated at its Ranger Anticline area located in the southern part of the basin in Arkansas. During 2005, the company successfully completed 34 out of 37 wells (excluding three wells in progress at year-end 2005). Southwestern drilled its first successful well at Ranger in 1997, and through year-end 2005, had successfully drilled 77 out of 87 wells, adding 82.1 net Bcf of reserves at a finding cost of $1.07 per Mcf, including reserve revisions. Net production at Ranger during 2005 was 5.6 Bcf, up from 3.5 Bcf produced in the area during 2004. The company beli eves that Ranger holds significant future development potential and intends to drill 50 to 60 wells in this area during 2006.
Late in the third quarter of 2005, the company drilled the initial exploratory well on its Midway prospect, targeting the Pennsylvanian and Ordovician section. The USA #1-24 well encountered approximately 230 feet of net pay by electric log calculation in the Pennsylvanian age Borum sands, which is the main producing horizon in the Ranger Anticline area. The company is currently testing these sands and will determine the development potential based on the results. The company has approximately 20,300 gross undeveloped acres in its Midway prospect area.
Fayetteville Shale Play - At December 31, 2005, the company held a total of approximately 865,000 net acres in the play area (720,000 net undeveloped acres, 20,000 net developed acres held by Fayetteville Shale production and approximately 125,000 net acres held by conventional production).
As of December 31, 2005, Southwestern had spud a total of 88 wells in the play, 86 of which were operated by the company and two of which were outside-operated wells. Of the 88 wells spud, 67 were drilled during 2005 and 21 were drilled in 2004. The wells are located in 15 separate pilot areas located in seven counties in Arkansas and, as of December 31, 2005, 54 were producing, 13 were in some stage of completion or waiting on pipeline hook-up and four were shut-in due to marginal performance or temporarily abandoned. The remaining 17 wells were in the drilling phase at year-end, including 13 horizontal wells which had been drilled through the vertical section with a smaller spudder rig and will be re-entered with a larger rig capable of drilling the horizontal section.
At December 31, 2005, 37 of the 88 wells spud are designated as horizontal wells, 13 of which were producing, five were completing, four were drilling, two were temporarily abandoned and 13 wells had been drilled through the vertical section.
During 2005, Southwestern invested approximately $154.5 million in its Fayetteville Shale play, which included $67.4 million to spud 67 wells, $40.7 million for leasehold acquisition, $35.1 million towards the fabrication of ten new drilling rigs to be utilized in the play, $4.3 million for seismic and $7.0 million in capitalized costs. Total proved gas reserves booked
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in the play as of year-end 2005 totaled 101.0 Bcf from a total of 177 locations, of which 54 were proved developed producing, 6 were proved developed non-producing and 117 were proved undeveloped. The average proved reserves for the horizontal wells included in the company's year-end reserves was approximately 0.95 gross Bcf per well. The company's estimated average ultimate gross production for these wells is 1.3 to 1.5 Bcf per horizontal well, based on the limited production data through December 31, 2005 and the company's reservoir simulation shale gas model.
The graph below provides average daily production data through February 14, 2006, for the company’s horizontal wells compared to 1.3 Bcf and 1.5 Bcf type curves from the company’s reservoir simulation shale gas model. The graph also shows the number of producing wells that are included in the average daily production data.
Through December 31, 2005, the Arkansas Oil and Gas Commission (AOGC) approved field rules for four fields in the Fayetteville Shale play area located in Conway, Van Buren and Faulkner counties. For each field, the AOGC approved governmental sections of approximately 640 acres as the drilling unit and well spacing requirements within each drilling unit of 560 feet minimum distance between completions in common sources of supply within the Fayetteville Shale formation, up to a maximum of 25 wells per drilling unit. At December 31, 2005, based on the assumptions contained in the field rule applications for these fields, Southwestern estimated the expected drainage from horizontal wells to be less than 80 acres per well based on existing microseismic data and reservoir simulation modeling.
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East Texas - During 2005, Southwestern drilled and completed a total of 89 wells in East Texas, of which 80 were located in its Overton Field in Smith County, Texas. The company has experienced a 100% success rate at Overton since it began its development drilling program in 2001. Daily gross production at the Overton Field has increased from approximately 2.0 MMcfe in March 2001 to approximately 109.7 MMcfe at year-end 2005, resulting in net production of 26.7 Bcfe during 2005, compared to 21.8 Bcfe in 2004. In 2006, Southwestern plans to drill approximately 83 wells at Overton.
At the company’s Angelina River Trend area located primarily in Nacogdoches County, Texas, Southwestern held approximately 11,000 gross undeveloped acres and 3,000 gross developed acres at year-end 2005. Through December 31, 2005, Southwestern had drilled nine wells with 100% success in this trend primarily targeting the Travis Peak formation. During 2006, the company intends to explore the growth potential of the Angelina River Trend by drilling a total of 16 wells in the area.
New Ventures - During 2005, Southwestern leased approximately 49,000 net undeveloped acres in the emerging Barnett Shale play in the Permian Basin. The company plans to drill a test well for the Barnett Shale interval in Culberson County, Texas, in the second quarter of 2006.
Current Update on Fayetteville Shale Play
Subsequent to December 31, 2005 and through February 27, 2006, Southwestern added a total of approximately 10,000 net acres, bringing the company’s total acreage position to 875,000 acres (730,000 net undeveloped acres, 20,000 net developed acres held by Fayetteville Shale production and approximately 125,000 net acres that is held by conventional production) in the play area.
Through February 27 of this year, Southwestern has spud an additional 26 wells and participated in three outside-operated wells and has drilled in two additional pilot areas in the Fayetteville Shale play. Of the 117 total wells drilled through February 27, 2005, 60 are producing, 17 are in some stage of completion or waiting on pipeline hook-up and six are shut-in due to marginal performance or temporarily abandoned. Additionally, 34 wells are in the drilling phase, including 29 which have been drilled through the vertical section of the well utilizing smaller “spudder” rigs and will be re-entered with one of the larger rigs for the drilling of the horizontal section.
Twenty-six of the 29 wells spud subsequent to December 31, 2005 and through February 27, 2006, are designated as horizontal wells. Of the 63 total horizontal wells spud through February 27 of this year, 17 are producing, 11 were completing, four were drilling, two were temporarily abandoned and 29 wells had been drilled through the vertical section. The average initial test rate for 16 of the 17 completed horizontal wells, excluding the company’s first horizontal well in which problems with wellbore isolation limited the stimulation treatment, is 2.2 MMcf per day. Most recent completed well costs for the horizontal wells have ranged between $1.4 million and $1.8 million per well, excluding non-recurring costs, and have taken 15 to 20 days on average to reach total depth.
As of February 27, 2006, Southwestern has four drilling rigs running in its Fayetteville Shale play area, three of which are capable of drilling horizontal wells and one smaller "spudder" rig is being used to drill the vertical section of the horizontal wells. The company entered
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into contractual commitments in 2005 for the construction of ten drilling rigs to be used in the play area. The first of the ten rigs was delivered in late-January 2006 and drilled its first well to total depth in eight days after re-entry. The remaining nine new rigs will be delivered throughout 2006 as each one is completed. In addition, the company expects to add two third-party rigs to be delivered in the play area by the end of the first quarter 2006.
Subsequent to December 31, 2005 and through February 27, 2006, the AOGC approved field rules for another field, the New Quitman Field, located in Cleburne and Faulkner counties in Arkansas. Southwestern expects to continue the evaluation of its acreage position in the Fayetteville Shale play by testing an additional 24 to 30 pilot areas by year-end 2006. Southwestern expects to drill 175 to 200 wells in the Fayetteville Shale play area in 2006.
In addition to the Fayetteville Shale, Southwestern has also recently tested gas production from the deeper Moorefield and Chattanooga Shales in the play area. The company’s Carter #1-35 vertical well located in its East Cutthroat pilot area in Cleburne County, Arkansas, was recently completed in the Moorefield Shale and tested 710 Mcf per day. Based on the company’s preliminary work, the Moorefield Shale has reservoir characteristics similar to the Fayetteville Shale, which it immediately underlies. Southwestern currently holds approximately 130,000 net undeveloped acres that could be prospective in the Moorefield Shale.
Additionally, Southwestern is currently testing the Chattanooga Shale in the Eschbach #1-12 well. The Eschbach well is located in the company’s Altus pilot area located in Franklin County, Arkansas. The Chattanooga Shale occurs below both the Fayetteville and Moorefield Shales at a depth of approximately 3,500 to 6,500 feet.
Explanation and Reconciliation of Non-GAAP Financial Measures
Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. The table below reconciles net cash provided by operating activities before change s in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.
| 3 Months Ended December 31, | | 12 Months Ended December 31, |
| 2005 | | 2004 | | 2005 | | 2004 |
Net cash provided by operating activities before changes in assets and liabilities | $ | 102,755 | | $ | 72,361 | | $ | 321,758 | | $ | 237,706 |
Add back (deduct): | | | | | | | | | | | |
Change in operating assets and liabilities | | (14,095) | | | (17,783) | | | (17,276) | | | 191 |
Net cash provided by operating activities | $ | 88,660 | | $ | 54,578 | | $ | 304,482 | | $ | 237,897 |
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Southwestern will host a teleconference call on Wednesday, March 1, 2006, at 10:00 a.m. Eastern to discuss the company’s fourth quarter and year-end 2005 financial and operating results. The toll-free number to call is 888-208-1812 and the reservation number is 4886738. The teleconference can also be heard “live” on the Internet athttp://www.swn.com.
Southwestern Energy Company is an integrated natural gas company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering, transmission, and marketing, and natural gas distribution. Additional information on the company can be found on the Internet athttp://www.swn.com.
Contacts:
Greg D. Kerley
Brad D. Sylvester, CFA
Executive Vice President
Manager, Investor Relations
and Chief Financial Officer
(281) 618-4897
(281) 618-4803
All statements, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in commodity prices for natural gas and oil; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the extent to which the Fayettev ille Shale play can replicate the results of other productive shale gas plays; the potential for significant variability in reservoir characteristics of the Fayetteville Shale over such a large acreage position; the extent of the company’s success in drilling and completing horizontal wells; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the company’s lack of experience owning and operating drilling rigs; the company’s ability to fund its planned capital expenditures; future property acquisition or divestiture activities; the effects of weather and regulation on the company’s gas distribution segment; increased competition; the impact of federal, state and local government regulation; the financial impact of accounting regulations and critical accounting policies; changing market conditions and prices (including regional basis differentials); the comparative cost of alternative fuels; conditions in capital markets and changes in interest rates; the availability of oil field
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personnel, services, drilling rigs and other equipment; and any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Financial Summary Follows
# # #
| | OPERATING STATISTICS (Unaudited) | | | | Page 1 of 5 | |
| | Southwestern Energy Company and Subsidiaries | | | | | | | |
| | | | | | | | | | | |
| | | | Three Months | | Twelve Months | |
| | Periods Ended December 31 | | 2005 | | 2004 | | 2005 | | 2004 | |
| | Exploration & Production | | | | | | | | | |
| | Production | | | | | | | | | |
| | Gas production (MMcf) | | 14,769 | | 14,131 | | 56,758 | | 50,424 | |
| | Oil production (MBbls) | | 162 | | 162 | | 705 | | 618 | |
| | Total equivalent production (MMcfe) | | 15,742 | | 15,103 | | 60,988 | | 54,132 | |
| | Commodity Prices | | | | | | | | | |
| | Average realized gas price per Mcf | | $7.51 | | $5.58 | | $6.51 | | $5.21 | |
| | Average realized oil price per Bbl | | $43.71 | | $37.00 | | $42.62 | | $31.47 | |
| | Operating Expenses per Mcfe | | | | | | | | | |
| | Lease operating expenses | | $0.51 | | $0.37 | | $0.48 | | $0.38 | |
| | Taxes, other than income taxes | | $0.40 | | $0.33 | | $0.37 | | $0.28 | |
| | General & administrative expenses | | $0.64 | | $0.39 | | $0.46 | | $0.36 | |
| | Full cost pool amortization | | $1.54 | | $1.23 | | $1.42 | | $1.20 | |
| | | | | | | | | | | |
| | Marketing | | | | | | | | | |
| | Gas volumes marketed (MMcf) | | 15,401 | | 15,694 | | 61,901 | | 56,975 | |
| | | | | | | | | | | |
| | Gas Distribution | | | | | | | | | |
| | Deliveries (Bcf) | | | | | | | | | |
| | Sales and end-use transportation | | 7.2 | | 7.2 | | 23.2 | | 24.0 | |
| | Off-system transportation | | - | | - | | - | | 1.0 | |
| | Number of customers - period end | | 147,820 | | 144,612 | | 147,820 | | 144,612 | |
| | Average sales rate per Mcf | | $14.30 | | $9.86 | | $11.85 | | $9.39 | |
| | Heating weather - degree days | | 1,513 | | 1,338 | | 3,744 | | 3,678 | |
| | - percent of normal | | 96% | | 85% | | 91% | | 90% | |
| | STATEMENTS OF OPERATIONS (Unaudited) | | Page 2 of 5 | |
| | Southwestern Energy Company and Subsidiaries | | | | | |
| | | | | | | | | |
| | | | Three Months | | Twelve Months | |
| | Periods Ended December 31 | | 2005 | | 2004 | | 2005 | | 2004 | |
| | | | (in thousands, except share/per share amounts) | |
| | Operating Revenues | | | | | | | | | |
| | Gas sales | | $ 165,182 | | $ 117,966 | | $ 503,111 | | $ 375,460 | |
| | Gas marketing | | 45,118 | | 22,278 | | 132,690 | | 65,127 | |
| | Oil sales | | 7,072 | | 6,001 | | 30,026 | | 19,461 | |
| | Gas transportation and other | | 3,314 | | 3,280 | | 10,502 | | 17,089 | |
| | | | 220,686 | | 149,525 | | 676,329 | | 477,137 | |
| | Operating Costs and Expenses | | | | | | | | | |
| | Gas purchases - gas distribution | | 37,817 | | 24,738 | | 82,689 | | 64,311 | |
| | Gas purchases - midstream services | | 41,830 | | 21,205 | | 124,730 | | 60,804 | |
| | Operating expenses | | 14,524 | | 10,877 | | 52,850 | | 42,157 | |
| | General and administrative expenses | | 16,602 | | 10,649 | | 48,650 | | 36,074 | |
| | Depreciation, depletion and amortization | | 27,428 | | 21,097 | | 96,211 | | 73,674 | |
| | Taxes, other than income taxes | | 7,173 | | 5,662 | | 25,279 | | 17,830 | |
| | | | 145,374 | | 94,228 | | 430,409 | | 294,850 | |
| | Operating Income | | 75,312 | | 55,297 | | 245,920 | | 182,287 | |
| | Interest Expense | | | | | | | | | |
| | Interest on long-term debt | | 3,580 | | 4,912 | | 19,791 | | 18,335 | |
| | Other interest charges | | 293 | | 333 | | 1,254 | | 1,461 | |
| | Interest capitalized | | (2,737) | | (797) | | (6,005) | | (2,804) | |
| | | | 1,136 | | 4,448 | | 15,040 | | 16,992 | |
| | Other Income (Expense) | | 4,158 | | 728 | | 4,784 | | (362) | |
| | Income Before Income Taxes and Minority Interest | | 78,334 | | 51,577 | | 235,664 | | 164,933 | |
| | Minority Interest in Partnership | | (588) | | (383) | | (1,473) | | (1,579) | |
| | Income Before Income Taxes | | 77,746 | | 51,194 | | 234,191 | | 163,354 | |
| | Provision for Income Taxes - Deferred | | 28,890 | | 18,279 | | 86,431 | | 59,778 | |
| | Net Income | | $ 48,856 | | $ 32,915 | | $ 147,760 | | $ 103,576 | |
| | Earnings Per Share: (1) | | | | | | | | | |
| | Basic | | $0.29 | | $0.23 | | $0.98 | | $0.72 | |
| | Diluted | | $0.29 | | $0.22 | | $0.95 | | $0.70 | |
| | Weighted Average Common Shares Outstanding: (1) | | | | | |
| | Basic | | 165,720,853 | | 143,625,400 | | 150,892,602 | | 142,902,404 | |
| | Diluted | | 171,139,488 | | 149,274,460 | | 156,309,039 | | 147,851,088 | |
(1) 2004 restated to reflect two two-for-one stock splits effected in June and November 2005.
| | BALANCE SHEETS (Unaudited) | | Page 3 of 5 | |
| | Southwestern Energy Company and Subsidiaries | | | | | |
| | | | | | | |
| | December 31 | | 2005 | | 2004 | |
| | | | (in thousands) | |
| | ASSETS | | | | | |
| | | | | | | |
| | Current Assets | | $ 461,064 | | $ 130,985 | |
| | Investments | | 17,100 | | 15,465 | |
| | Property, Plant and Equipment, at cost | | 2,242,615 | | 1,761,345 | |
| | Less: Accumulated depreciation, depletion and amortization | | 872,218 | | 777,189 | |
| | | | 1,370,397 | | 984,156 | |
| | Other Assets | | 19,963 | | 15,538 | |
| | | | $ 1,868,524 | | $1,146,144 | |
| | | | | | | |
| | LIABILITIES AND SHAREHOLDERS' EQUITY | |
| | | | | | | |
| | Current Liabilities | | $ 302,386 | | $ 133,700 | |
| | Long-Term Debt | | 100,000 | | 325,000 | |
| | Deferred Income Taxes | | 254,528 | | 203,996 | |
| | Long-term Hedging Liability | | 60,442 | | 5,798 | |
| | Other Liabilities | | 29,251 | | 18,114 | |
| | Commitments and Contingencies | | | | | |
| | Minority Interest in Partnership | | 11,613 | | 11,859 | |
| | Shareholders' Equity | | | | | |
| | Common stock, $.10 par value; authorized 220,000,000 shares,
issued 168,452,336 shares in 2005 (1) | | 16,845 | | 14,890 | |
| | Additional paid-in capital (1) | | 711,196 | | 117,586 | |
| | Retained earnings | | 498,221 | | 350,461 | |
| | Accumulated other comprehensive income (loss) | | (104,874) | | (19,816) | |
| | Common stock in treasury, at cost, 1,217,284 shares in 2005 and 3,286,304 shares in 2004 (1) | | (3,390) | | (9,156) | |
| | Unamortized cost of restricted shares issued under stock incentive plan, 707,142 shares in 2005 and 1,281,152 shares in 2004 (1) | | (7,694) | | (6,288) | |
| | | | 1,110,304 | | 447,677 | |
| | | | $ 1,868,524 | | $ 1,146,144 | |
(1) 2004 restated to reflect two two-for-one stock splits effected in June and November 2005.
| | STATEMENTS OF CASH FLOWS (Unaudited) | | | | Page 4 of 5 | |
| | Southwestern Energy Company and Subsidiaries | | | | | |
| | | | | | | |
| | | | Twelve Months | |
| | Periods Ended December 31 | | 2005 | | 2004 | |
| | | | (in thousands) | |
| | Cash Flows From Operating Activities | | | |
| | Net Income | | $ 147,760 | | $ 103,576 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| | Depreciation, depletion and amortization | | 99,558 | | 77,350 | |
| | Deferred income taxes | | 86,431 | | 59,778 | |
| | Unrealized (gain) loss on derivatives | | (9,666) | | 2,639 | |
| | Equity in (income) loss of NOARK partnership | | (1,635) | | 433 | |
| | Gain on sale of other property, plant & equipment | | (445) | | (5,802) | |
| | Minority interest in partnership | | (245) | | (268) | |
| | Change in operating assets and liabilities | | (17,276) | | 191 | |
| | Net cash provided by operating activities | | 304,482 | | 237,897 | |
| | | | | | | |
| | Cash Flows From Investing Activities | | | | | |
| | Capital expenditures | | (453,859) | | (291,101) | |
| | Investment in NOARK partnership | | - | | (2,059) | |
| | Proceeds from sale of property, plant & equipment | | 1,519 | | 7,121 | |
| | Other items | | (578) | | 591 | |
| | Net cash used in investing activities | | (452,918) | | (285,448) | |
| | | | | | | |
| | Cash Flow From Financing Activities | | | | | |
| | Issuance of common stock | | 579,956 | | - | |
| | Payments on revolving long-term debt | | (563,800) | | (395,100) | |
| | Borrowings under revolving long-term debt | | 463,800 | | 441,300 | |
| | Retirement of 6.70% Notes due December 2005 | | (125,000) | | - | |
| | Debt issuance costs | | (1,180) | | (1,514) | |
| | Change in bank drafts outstanding | | 11,860 | | (2,347) | |
| | Proceeds from exercise of common stock options | | 5,270 | | 5,170 | |
| | Net cash provided by financing activities | | 370,906 | | 47,509 | |
| | | | | | | |
| | Increase (decrease) in cash and cash equivalents | | 222,470 | | (42) | |
| | Cash and cash equivalents at beginning of year | | 1,235 | | 1,277 | |
| | Cash and cash equivalents at end of period | | $ 223,705 | | $ 1,235 | |
| | | | | | | | | | | |
| SEGMENT INFORMATION (Unaudited) | | | | | Page 5 of 5 |
| Southwestern Energy Company and Subsidiaries | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Exploration& Production | | Gas Distribution | | Midstream
Services & Other | | Eliminations | | Total |
| (in thousands) |
| Quarter Ending December 31, 2005 | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Revenues | $ | 119,382 | | $ | 71,032 | | $ | 155,468 | | $ | (125,196) | | $ | 220,686 |
| | Gas purchases | | - | | | 52,966 | | | 150,974 | | | (124,293) | | | 79,647 |
| | Operating expenses | | 8,096 | | | 6,696 | | | 482 | | | (750) | | | 14,524 |
| | General & administrative expenses | | 10,074 | | | 5,793 | | | 1,005 | | | (270) | | | 16,602 |
| | Depreciation, depletion & amortization | | 25,289 | | | 1,839 | | | 300 | | | - | | | 27,428 |
| | Taxes, other than income taxes | | 6,355 | | | 712 | | | 106 | | | - | | | 7,173 |
| Operating Income (Loss) | $ | 69,568 | | $ | 3,026 | | $ | 2,601 | | $ | 117 | | $ | 75,312 |
| | | | | | | | | | | | | | | | |
Capital Investments (1) | $ | 127,952 | | $ | 3,083 | | $ | 11,108 | | $ | - | | $ | 142,143 |
| | | | | | | | | | | | | | |
| Quarter Ending December 31, 2004 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Revenues | $ | 86,311 | | $ | 50,008 | | $ | 96,344 | | $ | (83,138) | | $ | 149,525 |
| | Gas purchases | | - | | | 33,745 | | | 95,159 | | | (82,961) | | | 45,943 |
| | Operating expenses | | 5,633 | | | 5,297 | | | - | | | (53) | | | 10,877 |
| | General & administrative expenses | | 5,884 | | | 4,682 | | | 306 | | | (223) | | | 10,649 |
| | Depreciation, depletion & amortization | | 19,284 | | | 1,752 | | | 61 | | | - | | | 21,097 |
| | Taxes, other than income taxes | | 4,919 | | | 708 | | | 35 | | | - | | | 5,662 |
| Operating Income (Loss) | $ | 50,591 | | $ | 3,824 | | $ | 783 | | $ | 99 | | $ | 55,297 |
| | | | | | | | | | | | | | |
| Capital Investments (1) | $ | 71,256 | | $ | 2,091 | | $ | 3,914 | | $ | - | | $ | 77,261 |
| | | | | | | | | | | | | |
| Twelve Months Ending December 31, 2005 | | | | | | |
| | | | | | | | | | | | | | | | |
| Revenues | $ | 403,234 | | $ | 178,482 | | $ | 460,783 | | $ | (366,170) | | $ | 676,329 |
| | Gas purchases | | - | | | 120,852 | | | 451,064 | | | (364,497) | | | 207,419 |
| | Operating expenses | | 29,035 | | | 24,442 | | | 488 | | | (1,115) | | | 52,850 |
| | General & administrative expenses | | 28,234 | | | 18,614 | | | 2,477 | | | (675) | | | 48,650 |
| | Depreciation, depletion & amortization | | 88,902 | | | 6,907 | | | 402 | | | - | | | 96,211 |
| | Taxes, other than income taxes | | 22,304 | | | 2,756 | | | 219 | | | - | | | 25,279 |
| Operating Income | $ | 234,759 | | $ | 4,911 | | $ | 6,133 | | $ | 117 | | $ | 245,920 |
| | | | | | | | | | | | | | | | |
| Capital Investments (1) | $ | 451,289 | | $ | 10,908 | | $ | 20,854 | | $ | - | | $ | 483,051 |
| | | | | | | | | | | | | | |
| Twelve Months Ending December 31, 2004 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Revenues | $ | 286,924 | | $ | 152,449 | | $ | 321,226 | | $ | (283,462) | | $ | 477,137 |
| | Gas purchases | | - | | | 97,274 | | | 310,654 | | | (282,813) | | | 125,115 |
| | Operating expenses | | 20,637 | | | 21,679 | | | - | | | (159) | | | 42,157 |
| | General & administrative expenses | | 19,684 | | | 15,778 | | | 1,201 | | | (589) | | | 36,074 |
| | Depreciation, depletion & amortization | | 66,924 | | | 6,592 | | | 158 | | | - | | | 73,674 |
| | Taxes, other than income taxes | | 15,094 | | | 2,610 | | | 126 | | | - | | | 17,830 |
| Operating Income | $ | 164,585 | | $ | 8,516 | | $ | 9,087 | | $ | 99 | | $ | 182,287 |
| | | | | | | | | | | | | | |
| Capital Investments (1) | $ | 281,988 | | $ | 7,298 | | $ | 5,704 | | $ | - | | $ | 294,990 |
(1) Capital expenditures include $3.3 million and $28.1 million for the three and twelve month periods ended December 31, 2005, respectively, and ($2.5) million and $3.9 million for the three and twelve month periods ended December 31, 2004, respectively, relating to the change in accrued expenditures between periods.
