HOUSTON, Dec. 15 /PRNewswire-FirstCall/ -- Southwestern Energy Company today announced a planned capital investment program for 2007 of $1,341 million, an increase of 45% over the $925 million currently forecasted for 2006. The company's 2007 capital program includes $1,237 million for its exploration and production (E&P) segment, $84 million for its midstream gathering segment and $20 million for improvements to its utility systems and for other corporate purposes.
"Our efforts to ramp up activity in the Fayetteville Shale play during 2006 will have a significant impact on our capital and operating plan in 2007," stated Harold M. Korell, President and Chief Executive Officer of Southwestern Energy. "During 2007, we plan to invest approximately $875 million in the Fayetteville Shale play which includes drilling 400 to 450 horizontal wells in the play, over 75% of which we will operate, along with a substantial 3-D seismic program. Our gross production from the Fayetteville Shale alone could approximate 300 MMcf per day by year-end 2007, up from the current rate of approximately 84 MMcf."
Southwestern's activity levels in its other two primary operating areas will remain strong in 2007 as well. During 2007, the company will invest approximately $163 million in East Texas, where it expects to drill 35 to 40 wells at its Overton Field in Smith County, Texas, and 25 to 30 wells in its Angelina River Trend in Nacogdoches County, Texas. In the company's conventional Arkoma Basin drilling program, it plans to invest approximately $116 million in 2007 to drill 100 to 110 wells, including 50 to 60 wells in the Ranger Anticline area in Yell County, Arkansas.
Southwestern also plans to invest $58 million in various other exploration and New Ventures projects, where the company plans to participate in up to 50 exploration and unconventional wells, including up to 10 wells in the Woodford Shale in Oklahoma and up to 30 wells in a new coalbed methane play in northern Louisiana. The remainder of the company's 2007 E&P capital ($25 million) will be allocated to drill up to 20 wells in the Permian Basin and the onshore Gulf Coast. In total, Southwestern plans to drill 650 to 700 wells in 2007, up from an estimated 400 wells drilled during 2006.
Of the $1,237 million E&P capital budget for 2007, approximately 82% ($1,012 million) will be invested in development and exploratory drilling. Additionally, the company plans to invest $93 million in seismic and other geological and geophysical (G&G) expenditures, $46 million in leasehold and $86 million in capitalized interest and expenses and other equipment, facilities and technology-related expenditures.
Of the $93 million budgeted for seismic and other G&G expenditures, up to $77 million is set aside to shoot 3-D seismic on the company's Fayetteville Shale acreage. To date, the company has obtained a total of 46 square miles of 3-D data in five separate pilot areas. Analysis of the data interpreted indicates it has the potential to be a positive economic factor in the long- term development of the company's substantial acreage position.
The company's $1.3 billion 2007 capital program is expected to be funded by proceeds from internally-generated cash flow, borrowings under its revolving credit facility and/or funds raised in the public debt and equity markets. Assuming the company's capital program is funded entirely through cash flow and debt borrowings (no asset divestitures or public equity offering), the company expects its long-term debt-to-total capitalization ratio to be approximately 36% at year-end 2007.
Southwestern Issues Guidance for 2007
Southwestern is targeting 2007 total oil and gas production of 105 to 110 Bcfe, an increase of 45 to 50% over the company's current forecasted 2006 production. Based on early production histories and modeling and assuming continued positive operational results, approximately 45 to 50 Bcf of the 2007 targeted gas production is projected to come from the company's activities in the Fayetteville Shale play.
Assuming a NYMEX commodity price for 2007 of $7.00 per Mcf of gas, the differential for the average price received for its gas production is expected to be approximately $0.65 - $0.70 per Mcf below the NYMEX Henry Hub index price, including the impact of the company's basis hedges. Assuming a NYMEX commodity price for 2007 of $60.00 per barrel of oil, the differential for the average price received for its oil production is expected to be approximately $1.00 per barrel below the West Texas Intermediate (WTI) crude oil price. Through a combination of fixed-price swaps and collars, Southwestern currently has approximately 65.0 Bcf of natural gas hedged in 2007 and 35.0 Bcf hedged in 2008. Of the 65.0 Bcf hedged in 2007, 31.0 Bcf has been hedged at an average NYMEX Henry Hub fixed swap price of $7.73 per Mcf and 34.0 Bcf has been hedged using costless collars with average NYMEX Henry Hub prices ranging from $6.93 to $12.34 per Mcf.
The company's midstream segment is expected to generate approximately $10 to $12 million in operating income in 2007 from its gathering and marketing activities. The company projects the operating income from its gas distribution segment will be approximately $7 to $8 million in 2007, assuming normal weather.
In 2007, the company expects its net interest expense to be $25 to $30 million, which assumes that the company's capital program is funded entirely through cash flow and debt borrowings. Income taxes in 2007 are estimated at 38% and all are assumed to be deferred. Assuming NYMEX commodity prices for 2007 of $7.00 per Mcf of gas and $60.00 per barrel of oil, the company's projected results for 2007 are as follows:
Estimated Production in 2007
1st 2nd 3rd 4th Full-Year
Quarter Quarter Quarter Quarter 2007
Estimated
Production:
Gas (Bcf) 19.1-20.1 23.1-24.1 28.1-29.5 31.0-32.5 101.3-106.2
Oil (MBbls) 145-150 145-150 155-160 160-165 605-625
Total Production
(Bcfe) 20.0-21.0 24.0-25.0 29.0-30.5 32.0-33.5 105.0-110.0
FY 2007
Projected
E&P Operating Expenses ($ per Mcfe)
Lease Operating Expenses $0.82 - $0.87
General & Administrative Expense $0.41 - $0.46
Taxes, Other Than Income Taxes $0.21 - $0.26
Full Cost Pool Amortization Rate(1) $2.15 - $2.25
Other Operating Income and Expenses ($ in millions)
Midstream Operating Income $10.0 - $12.0
Utility Operating Income $7.0 - $8.0
Minority Interest Deduction $0.5 - $1.0
Net Interest Expense $25.0 - $30.0
Income Tax Rate (100% Deferred) 38.0%
(1) The company's full cost pool amortization rate can vary from this
estimate due to changes in the level of proved oil and gas reserves
and changes in the levels of unevaluated costs.
Assuming NYMEX commodity prices of $7.00 per Mcf of gas and $60.00 per barrel of oil for 2007, the company is targeting net income of $200 - $205 million and net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure; see "Explanation and Reconciliation of Non-GAAP Financial Measures" below) of $590 - $600 million in 2007. The company expects its operating income to approximate $355 - $360 million and its net income plus interest, income tax expense, depreciation, depletion and amortization (also known as EBITDA, a non-GAAP measure; see "Explanation and Reconciliation of Non-GAAP Financial Measures" below) to be approximately $615 - $625 million in 2007. The company has also provided additional price scenarios and their corresponding estimated financial results for 2007 in the table below:
NYMEX
Commodity Net Operating Net
Prices Income Income Cash Flow (1) EBITDA (1)
$6.00 Gas $160 - $165 $290 - $295 $525 - $535 $550 - $560
$50.00 Oil Million Million Million Million
$7.00 Gas $200 - $205 $355 - $360 $590 - $600 $615 - $625
$60.00 Oil Million Million Million Million
$8.00 Gas $240 - $245 $420 - $425 $655 - $665 $680 - $690
$65.00 Oil Million Million Million Million
(1) Net cash provided by operating activities before changes in operating
assets and liabilities and EBITDA are non-GAAP measures; see
Explanation and Reconciliation of Non-GAAP Financial Measures below.
Current Update on Fayetteville Shale Play
Through December 11, 2006, Southwestern had drilled and completed a total of 157 wells in the Fayetteville Shale play, of which 104 were horizontal. Of the 104 horizontal wells, 77 wells were fracture stimulated using slickwater or crosslinked gel fluids. The wells are located in 28 separate pilot areas located in eight counties in Arkansas. In addition, 102 wells were in the drilling or completion phase at December 11, 2006.
At December 14, 2006, the company's gross production rate from the Fayetteville Shale was approximately 84 MMcf per day. Southwestern currently expects that its year-end 2006 production exit rate to be approximately 95 to 100 MMcf per day from the Fayetteville. At December 11, 2006, the company had an inventory of 28 wells waiting on completion compared to 27 wells at October 19, 2006, and 12 wells at July 31, 2006. Southwestern currently has three completion crews operating in the area and now expects to have four and one- half crews working by the end of April 2007. The graph below provides gross production data from the Fayetteville Shale play.
(Photo: http://www.newscom.com/cgi-bin/prnh/20061215/DAF024-a )
Earlier in 2006, the company moved away from completing wells using nitrogen foam fracture stimulations. Through December 11, 2006, the company had performed 77 slickwater or crosslinked gel fracture stimulation treatments on horizontal wells. Gross daily production information for the company's wells which were fracture-stimulated using slickwater and crosslinked gels are as follows:
Initial Test Rate Average Rate at Average Rate at Average Rate at
(AOGC Form 3) 30 Days 60 Days 90 Days
(# of wells) (# of wells) (# of wells) (# of wells)
1.5 MMcf per day 1.5 MMcf per day 1.3 MMcf per day 1.2 MMcf per day
(75) (57) (48) (42)
The company has continued to test various completion techniques, including using crosslinked gel and slickwater fluid treatments and various downhole mechanical equipment. Not all of these techniques have proven to be successful and have impacted the performance of some of the company's recent wells. The company plans to continue to test new completion techniques as it seeks to optimize its completion activity. Costs of the company's recently completed horizontal wells have averaged approximately $2.2 million per well, which is also the company's current guidance for wells drilled during 2007.
The graph below provides normalized average daily production data through December 11, 2006 for the company's horizontal wells using slickwater and crosslinked gel fluids. The "light blue" curve includes all wells, and the "dark blue" curve excludes eight wells which had significant mechanical issues that are negatively impacting the wells' production performance. The normalized production data in the graph after approximately 270 days includes data for only one well, the McNew #4-2-H which was the company's first horizontal well with a slickwater completion. This well had a 1,900-foot lateral and a smaller 3-stage fracture stimulation. Since that time, the company has increased the number of stimulation stages to between 5 and 10 and the lateral length has averaged approximately 2,375 feet. The normalized production curves provide a qualitative measure of the company's Fayetteville Shale wells' performance and should not be used to estimate an individual well's estimated ultimate recovery.
The 1.3 and 1.5 Bcf typecurves shown on the graph reflect the range of the company's current estimates of the expected performance of the average horizontal well completed in the Fayetteville Shale with either a slickwater or crosslinked gel fracture stimulation and are based on the limited production history currently available. These typecurves have shallower initial decline rates than the company's previous nitrogen foam frac typecurves. Currently, the company estimates that the expected ultimate recoveries for the 77 horizontal wells completed with slickwater or crosslinked gel fluids will range from 0.4 to 3.0 Bcf per well.
(Photo: http://www.newscom.com/cgi-bin/prnh/20061215/DAF024-b )
As of December 14, 2006, Southwestern had 19 drilling rigs running in its Fayetteville Shale play area, 14 of which are capable of drilling horizontal wells and 5 smaller rigs that are used to drill the vertical section of the horizontal wells. The company expects one rig to be delivered by year-end which will be able to drill horizontal wells, and one of the smaller rigs is expected to be released. Southwestern has been able to mitigate a portion of higher service costs through the utilization of its surface hole drilling program and increased efficiencies from its new fit-for-purpose drilling rigs. Year-to-date in 2006, the company has averaged 19.5 days from re-entry-to-re- entry (including moving between locations) utilizing the combination of the smaller rigs and larger rigs to drill the horizontal laterals, and it expects this time to be reduced to approximately 15 days during 2007. Southwestern currently plans to continue to utilize 19 rigs in the play area through 2007.
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. Forecasting changes in operating assets and liabilities would require unreasonable effort, would not be reliable and could be misleading. Therefore, the reconciliation of the company's forecasted net cash provided by operating activities before changes in operating assets and liabilities has assumed no changes in assets and liabilities.
2007 Guidance
NYMEX Commodity Price Assumptions
$6.00 Gas $7.00 Gas $8.00 Gas
$50.00 Oil $60.00 Oil $65.00 Oil
($ in millions)
Net cash provided by operating
activities $525-$535 $590-$600 $655-$665
Add back (deduct):
Assumed change in operating assets
and liabilities --- --- ---
Net cash provided by operating
activities before changes
in operating assets
and liabilities $525-$535 $590-$600 $655-$665
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles 2007 forecasted EBITDA with 2007 forecasted net income.
2007 Guidance
NYMEX Commodity Price Assumptions
$6.00 Gas $7.00 Gas $8.00 Gas
$50.00 Oil $60.00 Oil $65.00 Oil
($ in millions)
Net income $160-$165 $200-$205 $245-$250
Add back:
Provision for income taxes
- deferred 98-101 123-126 150-153
Interest expense 25-30 25-30 25-30
Depreciation, depletion
and amortization 270-280 270-280 270-280
EBITDA $550-$560 $615-$625 $680-$690
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 at http://www.swn.com/ .
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 availability of oil field personnel, services, drilling rigs and other equipment, including pressure pumping equipment and crews in the Arkoma Basin; the timing and extent of changes in commodity prices for natural gas and oil; the company's ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the timing and extent of the company's success in discovering, developing, producing and estimating reserves; the extent to which the Fayetteville 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 relative 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; 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.
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