Southwestern Energy Announces First Quarter 2013 Financial And Operating Results And Increases Production Guidance

HOUSTON, May 2, 2013 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the first quarter ended March 31, 2013. Highlights include:

• Gas and oil production of 147.8 Bcfe, up 11% compared to year-ago levels
• Adjusted net income of $146.0 million, up 37% compared to year-ago levels when excluding unrealized net gains and losses on derivative contracts (a non-GAAP measure reconciled below)
• Net cash provided by operating activities before changes in operating assets and liabilities of approximately $426.3 million, up 15% compared to year-ago levels (a non-GAAP measure reconciled below)
• Marcellus Shale gross operated production surpasses 400 MMcf per day in April

"We had a very good first quarter, which includes posting the highest first quarter cash flow in our company's history," remarked Steve Mueller, President and Chief Executive Officer of Southwestern Energy. "This results from our production which grew by 11% and our constant focus on keeping our costs low. Our gross operated production in the Marcellus Shale was slower than planned early in the quarter but reached 400 MMcf of gas per day in mid-April and, as a result, we have raised our production guidance in the latter half of the year. When you add on top of this the sizeable acreage acquisition in the Marcellus we announced earlier this week and our continued optimism about our New Ventures projects, we are looking forward to delivering even more value during 2013." 

First Quarter of 2013 Financial Results

For the first quarter of 2013, Southwestern reported net income of $127.5 million, or $0.36 per diluted share. Net income also included a non-cash unrealized net loss of $30.8 million ($18.5 million net of taxes) on derivative contracts associated with the company's hedging program. Excluding this non-cash item, Southwestern reported adjusted net income for the first quarter of 2013 of $146.0 million (reconciled below), or $0.42 per diluted share, compared to net income of $106.4 million, or $0.30 per diluted share, for the prior year period. Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was a record $426.3 million for the first quarter of 2013, compared to $370.8 million for the same period in 2012.

E&P Segment – Operating income from the company's E&P segment was $175.8 million for the three months ended March 31, 2013, compared to $114.6 million for the same period in 2012. The increase was primarily due to higher production volumes and lower operating costs and expenses, partially offset by lower realized natural gas prices.

Gas and oil production totaled 147.8 Bcfe in the first quarter of 2013, up 11% from 133.4 Bcfe in the first quarter of 2012, and included 118.9 Bcf from the company's Fayetteville Shale play, up from 115.8 Bcf in the first quarter of 2012. Production from the Marcellus Shale was 23.5 Bcf in the first quarter of 2013, compared to 9.3 Bcf in the first quarter of 2012. The company has updated its production guidance for the latter half of 2013 due to the strong performance it expects from its Marcellus Shale operating area. The revised total gas and oil production guidance for 2013 of 631 to 642 Bcfe is an increase of approximately 13% over the company's 2012 gas and oil production (using midpoints). The company's production guidance for the remainder of 2013 as follows:

Southwestern's average realized gas price in the first quarter of 2013 was $3.43 per Mcf, down from $3.48 per Mcf in the first quarter of 2012. The company's commodity hedging activities increased its average gas price by $0.55 per Mcf during the first quarter of 2013, compared to an increase of $1.24 per Mcf during the same period in 2012. As of April 30, 2013, the company had approximately 240 Bcf of its remaining 2013 expected gas production hedged at an average price of $4.71 per Mcf and approximately 233 Bcf of its 2014 forecasted gas production hedged at an average price of $4.41 per Mcf. As of March 31, 2013, the company had protected approximately 199 Bcf of its remaining 2013 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 ($0.06) 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. Disregarding the impact of hedges, the company's average price received for its gas production during the first quarter of 2013 was approximately $0.46 per Mcf lower than average NYMEX settlement prices, compared to approximately $0.50 per Mcf lower during the first quarter of 2012.

Lease operating expenses per unit of production for the company's E&P segment were $0.81 per Mcfe in the first quarter of 2013, compared to $0.83 per Mcfe in the first quarter of 2012. The decrease was primarily due to lower salt water disposal costs in the Fayetteville Shale.

General and administrative expenses per unit of production were $0.21 per Mcfe in the first quarter of 2013, down from $0.30 per Mcfe in the first quarter of 2012. The decrease was primarily due to lower employee-related and information systems costs.

Taxes other than income taxes per unit of production were $0.12 per Mcfe in the first quarter of 2013, compared to $0.13 in the first quarter of 2012. Taxes other than income taxes per Mcfe vary from period to period due to changes in severance and ad valorem taxes that result from the mix of the company's production volumes and fluctuations in commodity prices.

The company's full cost pool amortization rate decreased to $1.09 per Mcfe in the first quarter of 2013, compared to $1.33 per Mcfe in the first quarter of 2012. 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, write-downs 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 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 company's Midstream Services segment, which is comprised of natural gas gathering and marketing activities, was $76.3 million for the three months ended March 31, 2013, up from $69.3 million in the same period in 2012. The increase in operating income was primarily due to the increase in gathering revenues from the company's Fayetteville and Marcellus Shale properties from higher gathered volumes, partially offset by increased operating costs and expenses from higher activity. At March 31, 2013, the company's midstream segment was gathering approximately 2.2 Bcf per day through 1,859 miles of gathering lines in the Fayetteville Shale play. Gathering volumes, revenues and expenses for this segment are expected to grow over the next few years largely as a result of continued development of the company's acreage in the Fayetteville Shale and Marcellus Shale and development activity undertaken by other operators in those areas.

Capital Structure and Investments – At March 31, 2013, the company had approximately $1.7 billion in long-term debt and its long-term debt-to-total capitalization ratio was 35.6%, up from 35.5% at December 31, 2012. The company had approximately $35 million borrowed on its revolving credit facility and also had cash and cash equivalents and restricted cash of approximately $25 million at March 31, 2013.

In the first quarter of 2013, Southwestern invested approximately $518 million, down compared to $573 million in the first quarter of 2012, and included approximately $475 million invested in its E&P business, $39 million invested in its Midstream Services segment and $4 million invested for corporate and other purposes.

E&P Operations Review

During the first quarter of 2013, Southwestern invested a total of approximately $475 million in its E&P business, including $229 million in the Fayetteville Shale, $203 million in the Marcellus Shale, $2 million in its Ark-La-Tex division and $41 million in New Ventures.

Fayetteville Shale – For the first three months of 2013, Southwestern placed a total of 102 operated horizontal wells on production in the Fayetteville Shale. At March 31, 2013, the company's gross operated production rate was approximately 1,933 MMcf per day.

During the first quarter of 2013, the company's horizontal wells had an average completed well cost of $2.1 million per well, average horizontal lateral length of 4,942 feet and average time to drill to total depth of 5.4 days from re-entry to re-entry. This compares to an average completed well cost of $2.3 million per well, average horizontal lateral length of 4,784 feet and average time to drill to total depth of 5.7 days from re-entry to re-entry in the fourth quarter of 2012. In the first quarter of 2013, the company had 53 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. In total, the company has had a total of 296 wells drilled 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 2013 averaged initial production rates of 3,301 Mcf per day. Results from the company's drilling activities from 2007 by quarter are shown below.

In April of 2013, the company placed 40 wells on production at an average initial production rate of approximately 3,519 Mcf per day, 28 of which have peaked at an average rate of 3,710 Mcf per day with 12 wells still cleaning up.

Marcellus Shale – At March 31, 2013, Southwestern had 92 operated horizontal wells on production and 91 wells in progress in the Marcellus Shale, resulting in net production of 23.5 Bcf in the first quarter of 2013, more than double the 9.3 Bcf produced in the first quarter of 2012. Gross production from the company's operated wells in the Marcellus Shale was approximately 359 MMcf per day at March 31, 2013, and surpassed 400 MMcf per day in mid-April.

Of the 92 operated horizontal wells on production at March 31, 2013, 54 were located in Bradford County, 8 were located in Lycoming County and 30 were located in Susquehanna County. Of the 91 wells in progress at March 31, 2013, 40 were either waiting on completion or waiting to be placed to sales, including 14 in Bradford County, 2 in Lycoming County and 24 in Susquehanna County. A notable well placed on production during the quarter was the company's Blaine-Hoyd 4-H horizontal well, located in southern Bradford County, which was placed on production in late-March and reached a peak 24-hour production rate of 23.9 MMcf of gas per day. This well had a lateral length of 6,502 feet with 32 stages stimulated and flowed up casing. That compares to nearby wells that were also placed on production in 2013 with an average peak 24-hour rate of 10.1 MMcf per day, average lateral length of 4,229 feet and with 17 stages flowing up tubing only.

Results from the company's drilling activities from 2010 by quarter are shown below.

In April, the company signed a definitive purchase agreement to acquire approximately 162,000 net acres located near its existing position in Pennsylvania prospective for the Marcellus Shale for approximately $93 million, subject to closing conditions. The company believes that this transaction will close on or around May 15, 2013.

The graph below provides normalized average daily production data through March 31, 2013, for the company's horizontal wells in the Marcellus Shale. The "purple curve" indicates results for 46 wells with more than 12 fracture stimulation stages, the "orange curve" indicates results for 42 wells with 9 to 12 fracture stimulation stages and the "green curve" indicates results for 4 wells with less than 9 fracture stimulation stages. 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, 8 and 10 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/20130502/DA06579)

Ark-La-Tex – Total net production from the company's East Texas and conventional Arkoma Basin assets was 5.4 Bcfe in the first quarter of 2013, compared to 8.2 Bcfe in the first quarter of 2012.

New Ventures – Southwestern has approximately 507,000 net acres targeting the Lower Smackover Brown Dense (LSBD) formation located in southern Arkansas and northern Louisiana. The company has drilled eight operated wells in the play area to date, two of which are currently producing, one is being completed and one has recently been drilled. The company's BML #31-22 #1-1H horizontal well located in Union Parish, Louisiana, was placed on production in June 2012 and reached a peak production rate of 421 barrels of condensate per day and 3,900 Mcf of gas per day. This well was shut-in in early August and placed back on production in late November so that the gas could be gathered and sold. After 191 days on production, the BML well produced an average of 152 barrels of condensate per day and 1,510 Mcf of 1,220 Btu gas per day for the month of April. The company's Doles 30-22-1H #1 horizontal well located in Union Parish was placed on production in November 2012 and reached a peak production rate of 435 barrels of condensate per day and 2,500 Mcf of 1,250 Btu gas per day. After 173 days on production, the well produced an average of 95 barrels of condensate per day and 1,772 Mcf of gas per day in April. The company's Dean 31-22-2H Alt horizontal well in Union Parish was drilled to a total vertical depth of 10,055 feet with a planned completed lateral length of 3,169 feet. This well is currently being completed with 21 designed stages. The company's Sharp 22-22-1 #1 vertical well in Union Parish has been drilled to a total vertical depth of 9,776 feet. This well is scheduled to be completed in May.

Southwestern had previously announced a pending joint venture agreement in its LSBD exploration program. The period of exclusivity has lapsed and while an agreement may be reached with the original party, Southwestern has engaged in discussions with several other interested parties. The lack of a joint venture partner will not slow the company's testing of its LSBD exploration program.

Southwestern has approximately 302,000 net acres in the Denver-Julesburg Basin in eastern Colorado where it is targeting middle and late Pennsylvanian to Permian-age carbonates and shales. In February 2013, the company re-entered its vertical well, the Staner 5-58 #1-8 located in Arapahoe County, and drilled a 2,000-foot lateral in the Marmaton formation. The first 5 stages of a designed 16-stage fracture stimulation treatment have been completed and have begun flowback. The remaining 11 stages will be completed in the second quarter.

Explanation and Reconciliation of Non-GAAP Financial Measures

The company reports its 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 its 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.

Additional non-GAAP financial measures the company may present from time to time are net income, diluted earnings per share and its 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 company's 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, 2013 and March 31, 2012. 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.

Southwestern management will host a teleconference call on Friday, May 3, 2013 at 10:00 a.m. EDT to discuss its first quarter 2013 results. The toll-free number to call is 877-407-8035 and the international dial-in 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 independent energy 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 facts and 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, other than to the extent set forth below. 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 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 areas; the company's ability to fund the company's planned capital investments; the impact of federal, state and local government regulation, including any legislation relating to hydraulic fracturing, the climate or over the counter derivatives; the company's ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and the Marcellus Shale play; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the company's 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 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

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