HOUSTON, April 28, 2011 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the first quarter of 2011. Highlights include:
- Gas and oil production of 115.0 Bcfe, up 28% compared to year-ago levels; 2011 production guidance raised to 483 to 491 Bcfe, up from previous guidance of 465 to 475 Bcfe
- Net income and net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure reconciled below) both declined compared to year-ago levels due to 24% lower realized gas prices
- Strong well results in Marcellus Shale
For the first quarter of 2011, Southwestern reported net income of $136.6 million, or $0.39 per diluted share, compared to net income of $171.8 million, or $0.49 per diluted share, for the prior year period. Net cash provided by operating activities before changes in operating assets and liabilities (a non-GAAP measure; see reconciliation below) was $391.5 million for the first quarter of 2011, compared to $417.8 million for the same period in 2010. The company's first quarter comparative financial results were lower primarily due to a 24% decrease in average realized natural gas prices, partially offset by significant growth in the company's production volumes.
"Our first quarter financial and operating results have exceeded our expectations despite lower natural gas prices," remarked Steve Mueller, President and Chief Executive Officer of Southwestern Energy. "Our production continues to grow, and we increased our guidance for the rest of the year to take into account our first quarter results and the strong results we are continuing to see from both our Fayetteville and Marcellus drilling programs. Our all-in cash operating costs of $1.30 per Mcfe for the first quarter of 2011, which include lease operating expenses, general and administrative expenses, taxes other than income taxes and net interest expense, remain some of the lowest in our industry. As we look ahead, we are excited about moving to more development drilling in the Fayetteville Shale, increasing our activity in Pennsylvania and drilling our first wells on some new ideas we have been working on over the past two years."
First Quarter 2011 Financial Results
E&P Segment - Operating income from the company's E&P segment was $178.3 million for the three months ended March 31, 2011, compared to $250.4 million for the same period in 2010. The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses, partially offset by higher production.
Gas and oil production totaled 115.0 Bcfe in the first quarter of 2011, up 28% from 90.0 Bcfe in the first quarter of 2010, and included 101.1 Bcf from the company's Fayetteville Shale play, up from 75.5 Bcf in the first quarter of 2010. The company has updated its production guidance for the remainder of 2011 due to the strong performance from its Fayetteville Shale and Marcellus Shale operating areas. The revised total gas and oil production guidance for 2011 of 483 to 491 Bcfe is an increase of approximately 20% over the company's 2010 gas and oil production (using midpoints). Of the company's total expected production in 2011, approximately 425 to 435 Bcf is expected to come from the Fayetteville Shale. The company's production guidance for the remainder of 2011 as follows:
1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | Full-Year 2011 | ||
Actual | Estimate | Estimate | Estimate | Estimate | ||
Previous Guidance (Bcfe) | 109-111 | 115-117 | 119-121 | 122-126 | 465-475 | |
Revised Guidance (Bcfe) | 115.0 | 119-121 | 123-125 | 126-130 | 483-491 | |
Including the effect of hedges, Southwestern's average realized gas price in the first quarter of 2011 was $4.12 per Mcf, down 24% from $5.42 per Mcf in the first quarter of 2010. The company's commodity hedging activities increased its average gas price by $0.44 per Mcf during the first quarter of 2011, compared to an increase of $0.55 per Mcf during the same period in 2010. As of April 27, 2011, Southwestern had NYMEX price hedges in place on notional volumes of approximately 161 Bcf of its remaining 2011 gas production at a weighted average floor price of $5.27 per Mcf.
Disregarding the impact of commodity price hedges, the company's average price received for its gas production for each of the first quarters of 2011 and 2010 was approximately $0.43 per Mcf lower than average NYMEX settlement prices. As of April 28, 2011, the company had protected approximately 58 Bcf of its second quarter 2011 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 ($0.05) per Mcf. The company typically sells its natural gas at a discount to NYMEX settlement prices. This discount includes a basis differential, third-party transportation charges and fuel charges. In 2011, the company expects its total gas sales discount to NYMEX to be $0.45 to $0.50 per Mcf.
Lease operating expenses per unit of production for the company's E&P segment were $0.86 per Mcfe in the first quarter of 2011, compared to $0.78 per Mcfe in the first quarter of 2010. The increase was primarily due to increased gathering and water disposal costs related to its Fayetteville Shale operations.
General and administrative expenses per unit of production were $0.26 per Mcfe in the first quarter of 2011, compared to $0.29 per Mcfe in the first quarter of 2010. The decrease was primarily due to the effects of the company's increased production volumes which more than offset increased payroll, incentive compensation and other employee-related costs primarily associated with the expansion of the company's operations in the Fayetteville Shale play.
Taxes other than income taxes per unit of production were $0.12 per Mcfe in the first quarter of 2011, compared to $0.14 per Mcfe in the first quarter of 2010. Taxes other than income taxes vary due to changes in severance and ad valorem taxes that result from the mix of the company's volumes and fluctuations in commodity prices.
The company's full cost pool amortization rate decreased to $1.31 per Mcfe in the first quarter of 2011, compared to $1.41 per Mcfe in the first quarter of 2010. The decline in the average amortization rate was primarily the result of the sale of certain East Texas oil and natural gas leases and wells in the second quarter of 2010, as the proceeds from the sale were appropriately credited to the full cost pool, combined with lower acquisition and development costs. The amortization rate is impacted by the 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. The future full cost pool amortization rate cannot be predicted with accuracy due to the variability of each of the factors discussed above, as well as other factors.
Midstream Services - Operating income for the company's Midstream Services segment, which is comprised of natural gas gathering and marketing activities, was $53.9 million for the three months ended March 31, 2011, up from $37.6 million in the same period in 2010. The increase in operating income was primarily due to the increase in gathering revenues from the company's Fayetteville and Marcellus Shale plays, partially offset by increased operating costs and expenses.
At March 31, 2011, the company's Midstream Services segment was gathering approximately 1.9 Bcf per day through 1,623 miles of gathering lines in the Fayetteville Shale play, compared to gathering approximately 1.5 Bcf per day through 1,217 miles of gathering lines a year ago. Gathering volumes, revenues and expenses for this segment are expected to continue to grow as reserves related to the company's Fayetteville Shale play are developed and production increases and as it develops its Appalachian properties.
In March 2011, the company entered into a Letter of Intent with DTE Energy (NYSE: DTE) to gather its future natural gas production from its Range Trust area in its Marcellus Shale acreage in Susquehanna County, Pennsylvania. Final terms of the gathering agreement are currently being negotiated, however first volumes to be delivered to interstate pipelines could be as early as the second quarter of 2012. The company also recently executed agreements with both the Millennium Pipeline and the Tennessee Gas Pipeline that increases the company's ability to move its Marcellus production to premium markets.
The company is currently considering various strategic alternatives for maximizing and/or recognizing the value of its Fayetteville Shale gathering assets.
Capital Structure and Investments - At March 31, 2011, the company had approximately $1.2 billion in long-term debt and its long-term debt-to-total capitalization was 28.1%, compared to 27.0% at December 31, 2010. On February 14, 2011, Southwestern amended and restated its revolving credit facility which was scheduled to expire in February 2012. The maturity date of the unsecured credit facility was extended to February 2016 and the borrowing capacity was increased to $1.5 billion from $1.0 billion with an accordion feature that permits the company to increase the facility to $2.0 billion with agreement of existing or new lenders.
Due to the company's faster drilling times in the Fayetteville Shale than previously budgeted, Southwestern has increased its capital investments program for 2011 to approximately $2.0 billion, up from $1.9 billion. The increase in capital will result in approximately 30 additional wells drilled in its Fayetteville Shale play.
E&P Operations Review
Southwestern invested approximately $468 million in its E&P business during the first quarter of 2011, including $330 million invested in its Fayetteville Shale play, $52 million in Appalachia, $41 million in East Texas and $41 million in New Ventures.
Fayetteville Shale Play - For the first three months of 2011, Southwestern placed a total of 137 operated wells on production in the Fayetteville Shale play, all of which were horizontal wells fracture stimulated using slickwater. At March 31, 2011, the company's gross production rate from the Fayetteville Shale play was approximately 1,725 MMcf per day, up from approximately 1,330 MMcf per day a year ago. The company is currently utilizing 18 drilling rigs in its Fayetteville Shale play, including 11 that are capable of drilling horizontal wells and 7 smaller rigs that are used to drill the vertical portion of the wells. The graph below provides gross production data from the company's operated wells in the Fayetteville Shale play area through March 31, 2011.
(Photo: http://photos.prnewswire.com/prnh/20110428/DA91906-a)
During the first quarter of 2011, the company's horizontal wells had an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,985 feet and average time to drill to total depth of 8.4 days from re-entry to re-entry. This compares to an average completed well cost of $2.7 million per well, average horizontal lateral length of 4,667 feet and average time to drill to total depth of 8.2 days from re-entry to re-entry in the fourth quarter of 2010. In the first quarter of 2011, the company had 11 operated wells placed on production which had average times to drill to total depth of 5 days or less from re-entry to re-entry.
The company's wells placed on production during the first quarter of 2011 averaged initial production rates of 3,231 Mcf per day, down 7% from average initial production rates of 3,472 Mcf per day in the fourth quarter of 2010, primarily due to locational differences in the mix of wells and higher line pressures in certain parts of its gathering system where wells were brought on-line during the first quarter. Results from the company's drilling activities from 2007 by quarter are shown below.
Time Frame | Wells Placed on Production | Average IP Rate (Mcf/d) | 30th-Day Avg Rate (# of wells) | 60th-Day Avg Rate (# of wells) | Average Lateral Length | |
1st Qtr 2007 | 58 | 1,261 | 1,066 (58) | 958 (58) | 2,104 | |
2nd Qtr 2007 | 46 | 1,497 | 1,254 (46) | 1,034 (46) | 2,512 | |
3rd Qtr 2007 | 74 | 1,769 | 1,510 (72) | 1,334 (72) | 2,622 | |
4th Qtr 2007 | 77 | 2,027 | 1,690 (77) | 1,481 (77) | 3,193 | |
1st Qtr 2008 | 75 | 2,343 | 2,147 (75) | 1,943 (74) | 3,301 | |
2nd Qtr 2008 | 83 | 2,541 | 2,155 (83) | 1,886 (83) | 3,562 | |
3rd Qtr 2008 | 97 | 2,882 | 2,560 (97) | 2,349 (97) | 3,736 | |
4th Qtr 2008(1) | 74 | 3,350(1) | 2,722 (74) | 2,386 (74) | 3,850 | |
1st Qtr 2009(1) | 120 | 2,992(1) | 2,537 (120) | 2,293 (120) | 3,874 | |
2nd Qtr 2009 | 111 | 3,611 | 2,833 (111) | 2,556 (111) | 4,123 | |
3rd Qtr 2009 | 93 | 3,604 | 2,640 (92) | 2,275 (92) | 4,100 | |
4th Qtr 2009 | 122 | 3,727 | 2,674 (122) | 2,360 (120) | 4,303 | |
1st Qtr 2010(2) | 106 | 3,197(2) | 2,388 (106) | 2,123 (106) | 4,348 | |
2nd Qtr 2010 | 143 | 3,449 | 2,575 (141) | 2,329 (141) | 4,532 | |
3rd Qtr 2010 | 145 | 3,281 | 2,448 (145) | 2,202 (144) | 4,503 | |
4th Qtr 2010 | 159 | 3,472 | 2,678 (159) | 2,294 (159) | 4,667 | |
1st Qtr 2011 | 137 | 3,231 | 2,673 (104) | 2,351 (66) | 4,985 | |
Note: Results as of March 31, 2011. (1) 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. (2) In the first quarter of 2010, the company's results were impacted by the shift of all wells to "green completions" and the mix of wells, as a large percentage of wells were placed on production in the shallower northern and far eastern borders of the company's acreage. | ||||||
The company continues to test tighter well spacing and, at March 31, 2011, had placed 764 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less. Based on the wells drilled to date, the company now believes that approximately 30% of the approximately 600,000 net acres drilled to date can be developed at 30- to 50-acre spacing and approximately 70% can be developed at 65-acre spacing. The company believes that there could be slight changes in certain areas in the play where tighter spacing may occur in the future.
The graph below provides normalized average daily production data through March 31, 2011, for the company's 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 company's wells with lateral lengths greater than 3,000 feet, while the "purple curve" indicates results for the company's wells with lateral lengths greater than 4,000 feet and the "light blue curve" indicates results for the company's wells with lateral lengths greater than 5,000 feet. The normalized production curves are intended to provide a qualitative indication of the company's Fayetteville Shale wells' performance and should not be used to estimate an individual well's estimated ultimate recovery. The 2, 3 and 4 Bcf typecurves are shown solely for reference purposes and are not intended to be projections of the performance of the company's wells.
(Photo: http://photos.prnewswire.com/prnh/20110428/DA91906-b)
Appalachia - Southwestern has participated in a total of 21 wells in northeast Pennsylvania, of which 14 were successful and 7 were in progress at March 31, 2011. The producing wells are all operated Marcellus Shale wells located in its Greenzweig area in Bradford County. Net production from the area was 2.8 Bcf in the first quarter of 2011, compared to 0.8 Bcf in the fourth quarter of 2010.
In the Greenzweig area, the company's current practice is to place several wells on production from a single pad at the same time. Three wells that were placed on production in October 2010 are currently producing at an average gross rate of 6,276 Mcf per day per well, while three wells placed on production in November 2010 are currently producing at an average gross rate of 4,315 Mcf per day per well and three wells placed on production in February 2011 are currently producing at an average gross rate of 5,816 Mcf per day per well. On April 18th, the company placed three additional horizontal wells on production at a gross rate of over 4,000 Mcf per day per well while awaiting the installation of production tubing, which will allow higher producing rates. All of the production rates above are without the benefit of compression into lines pressures of approximately 1,000 psi. Gross operated production from the area is currently approximately 60 MMcf per day.
The graph below provides normalized average daily production data through March 31, 2011, for the company's horizontal wells in the Marcellus Shale. The "red curve" indicates results for the company's wells with lateral lengths less than 3,000 feet, while the "blue curve" indicates results for the company's wells with lateral lengths greater than 3,000 feet. The normalized production curves are intended to provide a qualitative indication of the company's Marcellus Shale wells' performance and should not be used to estimate an individual well's estimated ultimate recovery. The 4, 6 and 8 Bcf typecurves are shown solely for reference purposes and are not intended to be projections of the performance of the company's wells.
(Photo: http://photos.prnewswire.com/prnh/20110428/DA91906-c)
Other Areas - Total net production from the company's East Texas and conventional Arkoma Basin properties was 11.2 Bcfe in the first quarter of 2011, compared to 14.5 Bcfe in the first quarter of 2010. The company participated in drilling 2 wells in these areas during the quarter, both of which were operated.
In March 2011, Southwestern entered into a definitive purchase and sales agreement for the sale of certain oil and natural gas leases, wells and gathering equipment in Shelby, San Augustine and Sabine Counties in East Texas for approximately $85 million. The effective date of the sale is January 1, 2011 and the standard closing adjustments will include natural gas sales proceeds and capital invested in 2011 prior to the closing. The sale includes only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 9,700 net acres. The net production from the Haynesville and Middle Bossier Shale intervals in this acreage was approximately 7.3 MMcf per day as of April 15, 2011 and proved net reserves were approximately 25.1 Bcf as of year-end 2010. The transaction is expected to close in the second quarter of 2011.
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 company's 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.
See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2011 and March 31, 2010. 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.
3 Months Ended Mar. 31, | ||||
2011 | 2010 | |||
(in thousands) | ||||
Cash flow from operating activities: | ||||
Net cash provided by operating activities | $ 396,479 | $ 417,579 | ||
Add back (deduct): | ||||
Change in operating assets and liabilities | (4,947) | 186 | ||
Net cash provided by operating activities before changes in operating assets and liabilities | $ 391,532 | $ 417,765 | ||
Southwestern will host a teleconference call on Friday, April 29, 2011, at 10:00 a.m. Eastern to discuss the company's first quarter 2011 results. The toll-free number to call is 877-407-8035 and the international toll-free number is 201-689-8035. 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.
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 market conditions and prices for natural gas and oil (including regional basis differentials); the company's ability to fund the company's planned capital investments; the company's ability to transport its production to the most favorable markets or at all; the timing and extent of the company's success in discovering, developing, producing and estimating reserves; the economic viability of, and the company's success in drilling, the company's large acreage position in the Fayetteville Shale play overall as well as relative to other productive shale gas plays; the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over the counter derivatives; the costs and availability of oilfield personnel, services and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews; the company's ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the company's future property acquisition or divestiture activities; the impact of the adverse outcome of any material litigation against the company; the effects of weather; increased competition and regulation; 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 company's lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company's 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 | |||||
OPERATING STATISTICS (Unaudited) | |||||
Southwestern Energy Company and Subsidiaries | |||||
Three Months | |||||
Periods Ended March 31 | 2011 | 2010 | |||
Exploration & Production | |||||
Production | |||||
Gas production (Bcf) | 114.9 | 89.7 | |||
Oil production (MBbls) | 30 | 46 | |||
Total equivalent production (Bcfe) | 115.0 | 90.0 | |||
Commodity Prices | |||||
Average gas price per Mcf, including hedges | $ 4.12 | $ 5.42 | |||
Average gas price per Mcf, excluding hedges | $ 3.68 | $ 4.87 | |||
Average oil price per Bbl | $ 92.11 | $ 75.55 | |||
Operating Expenses per Mcfe | |||||
Lease operating expenses | $ 0.86 | $ 0.78 | |||
General & administrative expenses | $ 0.26 | $ 0.29 | |||
Taxes, other than income taxes | $ 0.12 | $ 0.14 | |||
Full cost pool amortization | $ 1.31 | $ 1.41 | |||
Midstream | |||||
Gas volumes marketed (Bcf) | 143.0 | 107.9 | |||
Gas volumes gathered (Bcf) | 171.5 | 125.7 | |||
STATEMENTS OF OPERATIONS (Unaudited) | ||||
Southwestern Energy Company and Subsidiaries | ||||
Three Months | ||||
Periods Ended March 31, | 2011 | 2010 | ||
(in thousands, except share/per share amounts) | ||||
Operating Revenues | ||||
Gas sales | $ 467,444 | $ 479,411 | ||
Gas marketing | 171,098 | 157,673 | ||
Oil sales | 2,727 | 3,462 | ||
Gas gathering | 34,581 | 25,373 | ||
Other | 485 | 2,198 | ||
676,335 | 668,117 | |||
Operating Costs and Expenses | ||||
Gas purchases - midstream services | 170,230 | 157,668 | ||
Operating expenses | 56,798 | 36,566 | ||
General and administrative expenses | 37,117 | 32,944 | ||
Depreciation, depletion and amortization | 163,447 | 139,017 | ||
Taxes, other than income taxes | 16,092 | 13,832 | ||
443,684 | 380,027 | |||
Operating Income | 232,651 | 288,090 | ||
Interest Expense | ||||
Interest on debt | 15,044 | 13,929 | ||
Other interest charges | 1,511 | 439 | ||
Interest capitalized | (9,119) | (7,860) | ||
7,436 | 6,508 | |||
Other Income, Net | 374 | 23 | ||
Income Before Income Taxes | 225,589 | 281,605 | ||
Provision for Income Taxes | ||||
Current | 100 | - | ||
Deferred | 88,880 | 109,837 | ||
88,980 | 109,837 | |||
Net income | 136,609 | 171,768 | ||
Less: net loss attributable to noncontrolling interest | - | (29) | ||
Net Income Attributable to Southwestern Energy | $ 136,609 | $ 171,797 | ||
Earnings Per Share | ||||
Net income attributable to Southwestern Energy stockholders - Basic | $ 0.39 | $ 0.50 | ||
Net income attributable to Southwestern Energy stockholders - Diluted | $ 0.39 | $ 0.49 | ||
Weighted Average Common Shares Outstanding | ||||
Basic | 346,833,906 | 345,099,247 | ||
Diluted | 349,697,327 | 349,397,997 | ||
BALANCE SHEETS (Unaudited) | ||||
Southwestern Energy Company and Subsidiaries | ||||
March 31, | 2011 | 2010 | ||
(in thousands) | ||||
ASSETS | ||||
Current Assets | $ 557,145 | $ 571,760 | ||
Property and Equipment | 9,516,988 | 7,662,143 | ||
Less: Accumulated depreciation, depletion and amortization | 3,861,053 | 3,199,635 | ||
5,655,935 | 4,462,508 | |||
Other Assets | 127,668 | 97,966 | ||
$ 6,340,748 | $ 5,132,234 | |||
LIABILITIES AND EQUITY | ||||
Current Liabilities | $ 695,191 | $ 618,057 | ||
Long-Term Debt | 1,202,900 | 1,017,800 | ||
Deferred Income Taxes | 1,203,334 | 859,171 | ||
Long-Term Hedging Liability | 60,651 | 2,380 | ||
Other Long-Term Liabilities | 93,379 | 82,441 | ||
Commitments and Contingencies | ||||
Equity | ||||
Common stock, $0.01 par value; authorized 1,250,000,000 shares in 2011 and 540,000,000 shares in 2010; issued 348,033,281 shares in 2011 and 346,192,064 in 2010 | 3,480 | 3,462 | ||
Additional paid-in capital | 870,065 | 837,751 | ||
Retained earnings | 2,155,054 | 1,586,124 | ||
Accumulated other comprehensive income | 59,442 | 119,778 | ||
Common stock in treasury, 125,077 shares in 2011 and 206,604 in 2010 | (2,748) | (4,457) | ||
Total Southwestern Energy Stockholders' Equity | 3,085,293 | 2,542,658 | ||
Noncontrolling Interest | - | 9,727 | ||
Total Equity | 3,085,293 | 2,552,385 | ||
$ 6,340,748 | $ 5,132,234 | |||
STATEMENTS OF CASH FLOWS (Unaudited) | |||||
Southwestern Energy Company and Subsidiaries | |||||
Three Months | |||||
Periods Ended March 31 | 2011 | 2010 | |||
(in thousands) | |||||
Cash Flows From Operating Activities | |||||
Net income | $ 136,609 | $ 171,768 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||
Depreciation, depletion and amortization | 164,667 | 139,419 | |||
Deferred income taxes | 88,880 | 109,837 | |||
Unrealized gain on derivatives | (1,080) | (4,487) | |||
Stock-based compensation | 2,450 | 2,297 | |||
Other | 6 | (1,069) | |||
Change in assets and liabilities | 4,947 | (186) | |||
Net cash provided by operating activities | 396,479 | 417,579 | |||
Cash Flows From Investing Activities | |||||
Capital investments | (526,139) | (442,122) | |||
Proceeds from sale of property and equipment | 11,056 | - | |||
Other | (375) | 649 | |||
Net cash used in investing activities | (515,458) | (441,473) | |||
Cash Flows From Financing Activities | |||||
Payments on revolving long-term debt | (782,800) | (621,600) | |||
Borrowings under revolving long-term debt | 892,700 | 641,900 | |||
Change in bank drafts outstanding | 17,749 | 4,057 | |||
Revolving credit facility costs | (10,103) | - | |||
Proceeds from exercise of common stock options | 2,743 | 253 | |||
Net cash provided by financing activities | 120,289 | 24,610 | |||
Effect of exchange rate changes on cash | 22 | - | |||
Increase in cash and cash equivalents | 1,332 | 716 | |||
Cash and cash equivalents at beginning of year | 16,055 | 13,184 | |||
Cash and cash equivalents at end of period | $ 17,387 | $ 13,900 | |||
SEGMENT INFORMATION (Unaudited) | ||||||||||
Southwestern Energy Company and Subsidiaries | ||||||||||
Exploration | ||||||||||
& | Midstream | |||||||||
Production | Services | Other | Eliminations | Total | ||||||
(in thousands) | ||||||||||
Quarter Ending March 31, 2011 | ||||||||||
Revenues | $ 476,170 | $ 679,268 | $ 776 | $ (479,879) | $ 676,335 | |||||
Gas purchases | - | 579,320 | - | (409,090) | 170,230 | |||||
Operating expenses | 98,945 | 27,866 | - | (70,013) | 56,798 | |||||
General & administrative expenses | 30,462 | 7,368 | 63 | (776) | 37,117 | |||||
Depreciation, depletion & amortization | 154,810 | 8,391 | 246 | - | 163,447 | |||||
Taxes, other than income taxes | 13,670 | 2,406 | 16 | - | 16,092 | |||||
Operating Income | $ 178,283 | $ 53,917 | $ 451 | $ - | $ 232,651 | |||||
Capital Investments (1) | $ 468,212 | $ 45,978 | $ 16,339 | $ - | $ 530,529 | |||||
Quarter Ending March 31, 2010 | ||||||||||
Revenues | $ 492,069 | $ 631,643 | $ 246 | $ (455,841) | $ 668,117 | |||||
Gas purchases | - | 560,003 | - | (402,335) | 157,668 | |||||
Operating expenses | 70,102 | 19,724 | - | (53,260) | 36,566 | |||||
General & administrative expenses | 26,339 | 6,804 | 47 | (246) | 32,944 | |||||
Depreciation, depletion & amortization | 132,707 | 6,161 | 149 | - | 139,017 | |||||
Taxes, other than income taxes | 12,490 | 1,327 | 15 | - | 13,832 | |||||
Operating Income | $ 250,431 | $ 37,624 | $ 35 | $ - | $ 288,090 | |||||
Capital Investments (1) | $ 411,433 | $ 49,266 | $ 12,926 | $ - | $ 473,625 | |||||
(1) Capital investments include increases of $1.5 million and $27.3 million for the three-month periods ended March 31, 2011 and 2010, respectively, relating to the change in accrued expenditures between periods. | ||||||||||
SOURCE Southwestern Energy Company
