Southwestern Energy Company 8-K 2009
SOUTHWESTERN ENERGY ANNOUNCES FIRST QUARTER 2009
FINANCIAL AND OPERATING RESULTS
Houston, Texas April 27, 2009...Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the first quarter of 2009. Highlights include:
Natural gas and crude oil production of 63.9 Bcfe, up 64% over the same period in 2008
Net cash provided by operating activities before changes in operating assets and liabilities of $372.6 million (a non-GAAP measure reconciled below), up 31% from the same period in 2008
Adjusted earnings of $125.5 million (a non-GAAP measure reconciled below), which excludes a non-cash ceiling test impairment of natural gas and oil properties, up 15% from the same period in 2008
For the first quarter of 2009, Southwestern reported a net loss of $432.8 million, or $1.26 per diluted share. Net income for the three months ended March 31, 2009 included a $907.8 million non-cash ceiling test impairment ($558.3 million net of taxes) of the companys natural gas and oil properties resulting from lower natural gas prices. Excluding the non-cash impairment, Southwestern reported net income for the first quarter of 2009 of $125.5 million (a non-GAAP measure; see reconciliation below), or $0.36 per diluted share, compared to net income of $109.0 million, or $0.31 per diluted share, for the same period in 2008. Southwestern accounts for its natural gas and oil properties using the full-cost method of accounting, which requires the company to perform a ceiling test that limits the amount of its capitalized gas and oil properties less accumulated amortization and related deferred income taxes to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties.
Net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure; see reconciliation below), was $372.6 million for the first quarter of 2009, up from $283.7 million for the same period in 2008. Excluding the non-cash impairment, the increase in the companys first quarter comparative financial results was driven primarily by the significant growth in production volumes from the Fayetteville Shale play, partially offset by lower realized natural gas prices.
We had a very productive first quarter, despite the effects of the recent decline in natural gas prices, remarked Harold M. Korell, Chairman and Chief Executive Officer of Southwestern Energy. Our production from the Fayetteville Shale continues to climb as we move up the learning curve in the play. Our gross operated production from the play reached approximately 850 MMcf per day at the end of the first quarter, compared to
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approximately 400 MMcf per day around this time last year. While we feel confident that natural gas prices will be higher for the longer-term, the price of gas has fallen approximately 35% from year-end 2008, thus causing a non-cash impairment of our oil and gas properties. As a result of the continuing low commodity price environment, we are reducing our planned capital program for 2009 by an additional $100 million down to $1.8 billion, which is approximately flat with our 2008 capital investments. The important thing to know is that commodity prices move in cycles and with the decreased drilling activity in our industry we are now positioned for an upturn in commodity prices. With our growing production volumes and financial flexibility, Southwestern Energy is well-positioned to benefit.
First Quarter 2009 Financial Results
E&P Segment - Excluding the non-cash ceiling test impairment, operating income from the companys E&P segment was $179.9 million for the three months ended March 31, 2009 (a non-GAAP measure; see reconciliation below), compared to $165.7 million for the same period in 2008. The increase was primarily due to higher production which was partially offset by lower realized natural gas prices and increased operating costs and expenses.
Gas and oil production totaled 63.9 Bcfe in the first quarter of 2009, up from 39.1 Bcfe in the first quarter of 2008, and included 50.2 Bcf from the companys Fayetteville Shale play, up from 23.6 Bcf in the first quarter of 2008. Southwestern has increased its production guidance for the remainder of 2009 as follows:
The revised total gas and oil production guidance for 2009 of 289 to 292 Bcfe is an increase of approximately 49% over the companys 2008 gas and oil production. Of the 289 to 292 Bcfe of expected production in 2009, approximately 238 to 240 Bcf is expected to come from the Fayetteville Shale.
During 2008, the majority of the companys gas from the Arkoma Basin was moved to markets in the Midwest. Phase 1 of the Fayetteville Lateral portion of the Texas Gas Transmission Pipeline (Boardwalk Pipeline) was placed in-service on December 24, 2008 providing additional capacity to the Midwest markets. On April 1, 2009, both Fayetteville and Greenville Laterals were placed in-service and the company began transporting a portion of its gas to Eastern markets. In April 2009, Texas Gas announced that there would be temporary reductions on the Fayetteville Lateral due to various activities, including maintenance and pipeline inspection. The exact completion date for these activities is unknown, but is expected to occur by the end of the third quarter. As a result, transportation on the Fayetteville Lateral as of April 24, 2009 was approximately 700,000 MMBtu per day, and the companys capacity was approximately 500,000 MMBtu per day to Bald Knob, Arkansas including 365,000 MMBtu per day to Lula, Mississippi. The company expects that the remainder of its Fayetteville Shale production will continue to be transported on other pipelines to Midwest markets until these issues are resolved.
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Including the effect of hedges, Southwesterns average realized gas price in the first quarter of 2009 was $5.94 per Mcf, down from $7.70 per Mcf in the first quarter of 2008. The companys commodity hedging activities increased its average gas price by $2.13 per Mcf during the first quarter of 2009 and by $0.24 per Mcf during the same period in 2008. Disregarding the impact of commodity price hedges, the companys average price received for its gas production during the first quarter of 2009 was approximately $1.08 per Mcf lower than average NYMEX spot prices, compared to approximately $0.57 per Mcf lower during the first quarter of 2008 due to widening basis differentials.
Beginning in the second quarter of 2009, the company believes that average basis differentials going forward will be lower than the differentials experienced during the second half of 2008 and first quarter of 2009. As of April 24, 2009, the company had protected approximately 45.1 Bcf of its second quarter 2009 expected gas production from the potential of widening basis differentials through hedging activities and sales arrangements at an average basis differential to NYMEX gas prices of approximately $0.25 per Mcf, excluding transportation charges and fuel charges. As of that same date for the third and fourth quarters of 2009, the company had protected approximately 49.1 and 36.4 Bcf, respectively, at average basis differentials to NYMEX gas prices of $0.25 per Mcf and $0.20 per Mcf, excluding transportation and fuel charges. The company typically sells its natural gas at a discount to NYMEX spot prices due to locational basis differentials, transportation charges and fuel charges.
Lease operating expenses per unit of production for the companys E&P segment were $0.78 per Mcfe in the first quarter of 2009, compared to $0.77 per Mcfe in the first quarter of 2008. The modest increase was the result of higher per unit operating costs associated with the companys Fayetteville Shale operations, partially offset by the impact that lower natural gas prices had on the cost of compressor fuel in the first quarter of 2009.
General and administrative expenses per unit of production were $0.31 per Mcfe in the first quarter of 2009, compared to $0.42 per Mcfe in the first quarter of 2008. The decrease was primarily due to the effects of the companys increased production volumes which more than offset increased compensation and related costs primarily associated with the expansion of the companys E&P operations due to the Fayetteville Shale play.
Taxes other than income taxes per unit of production were $0.13 per Mcfe in the first quarter of 2009, compared to $0.16 per Mcfe in the first quarter of 2008, primarily due to the change in the mix of the companys production volumes and fluctuations in commodity prices.
The companys full cost pool amortization rate decreased to $1.82 per Mcfe in the first quarter of 2009, compared to $2.30 per Mcfe in the first quarter of 2008. The decline in the average amortization rate was the result of the sale of natural gas and oil properties in the second and third quarters of 2008, as the proceeds from these sales were credited to the full cost pool, combined with the impact of lower finding and development costs in 2008. The amortization rate is impacted by timing and amount of reserve additions and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, impairments that result from full cost ceiling tests, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. As a result of the $907.8 million non-cash ceiling test impairment, the
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company expects that its amortization rate going forward, with all other factors considered in the ceiling test impairment computation remaining constant, will be reduced by between $0.30 to $0.40 per Mcfe; however, the company cannot predict its future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors.
Midstream Services - Operating income for the companys midstream services segment, which is comprised of natural gas gathering and marketing activities, was $27.4 million for the three months ended March 31, 2009, up from $10.2 million in the same period in 2008. The increase in operating income was primarily due to the increase in gathering revenues from the companys Fayetteville Shale play and an increase in the margin from gas marketing activities. At March 31, 2009, the companys midstream segment was gathering approximately 918 MMcf per day through 892 miles of gathering lines in the Fayetteville Shale play area, up from approximately 470 MMcf per day a year ago. Gathering volumes, revenues and expenses for this segment are expected to continue to grow as reserves related to the companys Fayetteville Shale play are developed and production increases.
E&P Operations Review
Southwestern invested a total of $450.4 million in its E&P business during the first quarter of 2009, including approximately $367.8 million invested in its Fayetteville Shale play, $34.5 million in East Texas, $18.3 million in its conventional Arkoma Basin program and $22.2 million in New Ventures.
Fayetteville Shale Play - Through March 31, 2009, Southwestern had drilled and completed a total of 938 operated wells in the Fayetteville Shale play, of which 856 are horizontal wells. Of the 856 horizontal wells, 798 wells have been fracture stimulated using slickwater or crosslinked gel fluids.
At March 31, 2009, the companys gross production rate from the Fayetteville Shale play was approximately 850 MMcf per day, up from approximately 400 MMcf per day a year ago. The graph below provides gross production data from the companys operated wells in the Fayetteville Shale play area.
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During the first quarter of 2009, the companys horizontal wells had an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,874 feet and average time to drill to total depth of 12 days from re-entry to re-entry. This compares to an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,850 feet and average time to drill to total depth of 13 days from re-entry to re-entry in the fourth quarter of 2008. The company currently has 19 drilling rigs running in its Fayetteville Shale play area, 15 that are capable of drilling horizontal wells and 4 smaller rigs that are used to drill the vertical portion of the wells. The company plans to exit the year with 11 rigs capable of drilling horizontal wells and 4 smaller rigs, and currently expects its gross well count in the play during 2009 to be 600 wells (75% operated), which is approximately the same number of wells drilled during 2008.
Since 2007, the continuous improvement of the companys completion practices have resulted in quarter-over-quarter improvements in average initial production rates of operated wells placed on production. The significant increase in the average initial production rate for the fourth quarter of 2008 and the subsequent decrease for the first quarter of 2009 primarily reflected the impact of the delay in the Boardwalk Pipeline. Initial rates were higher in the delayed wells placed on-line during the fourth quarter because wells were shut-in for a longer period of time before being placed on production. In addition, the company generally placed wells with the highest initial rates on production first throughout the fourth quarter of 2008. As a result, the remaining backlog of delayed wells that were placed on production in the first quarter of 2009 generally had lower rates, particularly during January and February. Wells that were placed on production in January and February of 2009 had average initial production rates of 2,806 Mcf per day and 2,749 Mcf per day, respectively, while wells placed on production during March 2009 had average initial production rates of 3,375 Mcf per day. During the first half of April 2009, the company had placed 27 wells on production at an average initial production rate of 3,763 Mcf per day.
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Results from the companys drilling activities from 2007 through 2009, by quarter, are shown below.
Note: Results as of March 31, 2009.
SW Slickwater fluids
XL Crosslinked gel fluids
Hy-RHy Hybrid or Reverse Hybrid method (combination slickwater/crosslinked gel fluid system)
(1) See discussion regarding 4th quarter 2008 and 1st quarter 2009 results in preceding paragraph.
The graph below provides normalized average daily production data through March 31, 2009, for the companys horizontal wells using slickwater and crosslinked gel fluids. The dark blue curve is for horizontal wells fracture stimulated with either slickwater or crosslinked gel fluid. The red curve indicates results for the companys wells with lateral lengths greater than 3,000 feet, while the purple curve indicates results for the companys wells with lateral lengths greater than 4,000 feet. The normalized production curves are intended to provide a qualitative indication of the companys Fayetteville Shale wells performance and should not be used to estimate an individual wells estimated ultimate recovery. The 2.0, 2.5 and 3.0 Bcf typecurves are shown solely for reference purposes and are not intended to be projections of the performance of the companys wells.
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At March 31, 2009, Southwestern held approximately 875,000 net acres in the play area (including 125,372 net acres in the traditional Fairway portion of the Arkoma Basin).
Conventional Arkoma Program - (Outside the Fayetteville Shale play area) Southwestern participated in drilling 9 wells in its conventional Arkoma Basin drilling program during the first three months of 2009. Production from the companys conventional Arkoma Basin was 5.8 Bcf for the first three months of 2009, compared to 5.9 Bcf for the first three months of 2008.
East Texas - Southwestern participated in drilling 11 wells in East Texas during the first three months of 2009, 9 of which were James Lime horizontal wells. Production from the companys East Texas properties was 7.8 Bcfe for the first three months of 2009, compared to 8.1 Bcfe for the first three months of 2008.
At March 31, 2009, Southwestern held approximately 105,700 gross acres in its Angelina River Trend area, which consists of several separate development areas located primarily in four different counties in East Texas where the company is targeting the Pettet, Travis Peak, James Lime and Haynesville formations. During the past year, the company has primarily focused its drilling activity in this area on the James Lime formation where it has 21 operated wells on production which had average gross initial production rates of 8.8 MMcf per day. Southwesterns current net production from the James Lime is approximately 30 MMcf per day, including production from 16 outside-operated wells.
In the second quarter of 2008, Southwestern signed a 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville/Bossier Shale intervals in Shelby and San Augustine Counties, Texas. The first horizontal well, the Red River 877 #1
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located in Shelby County, reached total depth in the fourth quarter of 2008, was production tested at 7.2 MMcfe per day in the first quarter of 2009 and is currently producing approximately 3.0 MMcf per day. The second horizontal well, the Red River 164 #1, has reached total depth and it is expected to be completed and tested in the second quarter of 2009. Pending further results from these wells, the company may invest more capital in the Haynesville/Bossier Shale play than previously planned.
New Ventures - At March 31, 2009, Southwestern held approximately 158,000 net undeveloped acres in the United States outside of its core operating areas in connection with New Ventures, including approximately 138,600 net acres in Pennsylvania under which it believes the Marcellus Shale is prospective.
Explanation and Reconciliation of Non-GAAP Financial Measures
We report our financial results in accordance with accounting principles generally accepted in the United States of America (GAAP). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods.
One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production companys ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.
Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy, diluted earnings per share attributable to Southwestern Energy stockholders and our E&P segment operating income, all which exclude certain charges or amounts. Management presents these measures because (i) they are consistent with the manner in which the Companys performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.
See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2009 and March 31, 2008. Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.
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Southwestern will host a teleconference call on Tuesday, April 28, 2009, at 10:00 a.m. Eastern to discuss the companys first quarter 2009 results. The toll-free number to call is 888-765-5554 and the reservation number is 4619368. The teleconference can also be heard live on the Internet at http://www.swn.com.
Southwestern Energy Company is an integrated company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering and marketing. Additional information on the company can be found on the Internet at http://www.swn.com.
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Greg D. Kerley
Brad D. Sylvester, CFA
Executive Vice President
Vice President, Investor Relations
and Chief Financial Officer
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 companys 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 companys 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 companys 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 market conditions and prices for natural gas and oil (including regional basis differentials); the companys ability to transport its production to the most favorable markets or at all; the timing and extent of the companys success in discovering, developing, producing and estimating reserves; the economic viability of, and the companys success in drilling, the companys large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas plays; the companys ability to fund the companys planned capital investments; the companys ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the impact of federal, state and local government regulation, including any increase in severance taxes; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the companys future property acquisition or divestiture activities; increased competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the companys lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the companys counterparties and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see the 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
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(1) Cash and cash equivalents at the beginning of the year for 2008 and at March 31, 2008 include $1.1 million and $1.7 million, respectively, classified as held for sale.
The three-month period ended March 31, 2008 includes operating results and capital investments associated with our natural gas distribution subsidiary, Arkansas Western Gas (AWG). On July 1, 2008, we closed the sale of AWG and, as a result, we no longer have any natural distribution operations.
Capital investments include increases of $23.6 million and $16.8 million for the three-month periods ended March 31, 2009 and 2008, respectively, relating to the change in accrued expenditures between periods.