Southwestern Energy First Quarter2013Earnings Teleconference

Speakers:

Steve Mueller; President and Chief Executive Officer

Bill Way,  Executive Vice President and Chief Operating Officer

Craig Owen;  Senior Vice President and Chief Financial Officer

Steve Mueller; President and Chief Executive Officer

Good morning and thank you for joining us.  With me today are Bill Way, our Chief Operating Officer, Craig Owen, our Chief Financial Officer, Jeff Sherrick, Senior VP of Corporate Development, and Brad Sylvester, our VP of Investor Relations.

If you have not received a copy of yesterday’s press release regarding our first quarter 2013 results, you can find a copy of all of this on our website at www.swn.com. Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To begin, we had a very good quarter. Our production grew 11% and our costs continue to decrease, resulting in the strongest cash flow in any first quarter in the company’s history.

Since the end of the first quarter, gas prices have improved and our production in the Marcellus has started to grow dramatically. As a result, we have raised our production guidance in the latter half of the year.

Earlier this week, we announced the acquisition of 162,000 additional acres in the Marcellus. Because it will take time to fully understand all of the infrastructure needs, our acquisition analysis assumed little activity on this acreage in 2013. Be assured we will quickly analyze how best to integrate this acreage into our current drilling program and will update you later in the year how this acquisition changes our Marcellus project.

Many have asked over the past several weeks if, due to the recent run-up in gas prices, we would increase our capital program. We certainly are encouraged by the increasingly better gas fundamentals but, except for the acquisition, we do not currently plan to accelerate our activity levels. So, while we are enjoying the recent increase in gas prices and production, we will continue to be disciplined in our capital investments, focused on lowering our costs and deliver “more” throughout the rest of 2013. 

I will now turn the call over to Bill for more details on our operations and then to Craig for a recap of our financial results. 

Bill Way, Executive Vice President and Chief Operating Officer

Thank you, Steve, and good morning everyone.  We achieved several key milestones in the first quarter which I want to share with you.  We grew our production by 11% compared to the same period in 2012. 

In addition, we continued to improve drilling times, lower our costs and we are seeing some PUD reserves begin to return to the books due to price.  Our strong focus on health, safety and the environment resulted in continued improvement in HS&E performance.

We did experience some early challenges during the quarter, specifically due to timing of getting wells on-line in our Marcellus area.  Typical minor bottlenecks created by rapid activity are now behind us as a result of the efforts of our team in Pennsylvania and our operational ramp is already showing results.

Marcellus Shale

Since I mentioned Marcellus, let me begin there.  We got off to a slower start than what we had planned due to various timing and logistical delays for getting wells connected to sales. This was especially troublesome in January, where we were only able to put 2 wells on production. 

However, we adjusted and quickly resumed our ramp up of the business and brought on to sales 19 additional wells by the end of the quarter.  We are hitting our full stride and we are back on pace in terms of production growth. Our gross operated production continuing to ramp up and has already reached 400 million cubic feet of gas per day, we are on plan to surpass 500 million cubic feet of gas per day by year-end.

Our Marcellus business will continue to grow in line with available gas transportation infrastructure.  We currently have agreements in place that increases our firm transportation capacity out of the area to 757 million cubic feet per day by 2015.

Back on the operations side, as we move into new areas, we continue to experiment with our stage counts and lateral lengths to optimize our wells. We averaged 17 stages per well in the first quarter, compared to an average of 12 stages in 2012.

We completed a test on our Blaine-Hoyd well in southern Bradford County this quarter that included 32 stages in the completion. This well had a peak 24-hour rate of 23.9 million cubic feet of gas per day and 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.

We know some shale formations have experienced long term effects producing with such high early drawdowns so we will continue to evaluate the technical and economic impacts of high density and high rate production in the Greenzweig area as well as in Susquehanna and Lycoming Counties.

While we realize that each area is different geologically, we will continue to experiment with our fracture stimulations, lateral lengths and flow techniques to optimize our wells throughout the rest of 2013.  We have 18 more tests planned for 2013.

I would also note that none of our Lycoming County or Northern Susquehanna wells are aided by compression at this point, so these wells are flowing against lines pressures between 1,200 and 1,400 pounds per square inch. Once compression is installed in the summer, the wells in these areas will be able to flow against lower line pressures and produce at higher rates.

On the midstream side, our owned and contracted gas gathering business in the Marcellus was gathering approximately 359 million cubic feet of natural gas per day from 67 miles of gathering lines in the field at March 31.

We are also very excited about our announcement earlier this week of the 162,000 net acres we agreed to purchase near our existing position in Pennsylvania. We are beginning to plan the integration of these properties into our program and evaluating where we will begin drilling in some of these new areas later on in the year. Our initial thought on this is that we would begin to drill 1-2 additional wells on this new acreage during the fourth quarter.

Fayetteville Shale Play

In the Fayetteville Shale, we placed 102 operated horizontal wells on production in the first quarter at an average completed well cost of $2.1 million per well. This record-low well cost is a testament to our strong team in Arkansas, the vertical services integration we have in the field and our commitment to driving our costs lower.

We also set a new record for average time to drill to total depth of just 5.4 days from re-entry to re-entry and placed 53 wells on production during the quarter that were drilled in 5 days or less.  In total, we have drilled 296 wells to date in 5 days or less.

During the first quarter, the initial production rates from the wells drilled was an average of 3.3 million cubic feet of gas per day. 

While these rates were lower than previous quarters and in keeping with the rigor of our value-added investing, the resulting economic value from these wells more than exceeded our 1.3 PVI hurdle rates due to our lower average well costs.

Our company-operated frac services were up to speed faster and have already made a meaningful impact to our overall well costs.  Our continuing optimization and testing of the drilling program is working and continues to deliver strong returns.

In April, we have already placed a number of strong wells on production on the Eastern side of the play which have had peak initial production rates in excess of 3.5 million cubic feet of gas per day, with several wells still climbing while cleaning up.

On the midstream side, our gas gathering business in the Fayetteville Shale continues to perform well and at March 31 was gathering approximately 2.2 billion cubic feet of natural gas per day from 1,859 miles of gathering lines in the field.

New Ventures

Switching to New Ventures, to date in the Brown Dense we have drilled 8 wells.  We remain encouraged after watching the production flows from our BML and Doles wells over the past several months,.  We are currently completing 21 stages that are planned in our seventh well, the Dean horizontal, and will test several different frac techniques to try and unlock more hydrocarbons from the formation.  Our eighth well, the Sharp vertical, is planned to be completed later this month.

We have also seen industry activity pick up the area, as several operators have requested new drilling permits and 7 unit filings have been approved for operators targeting the Brown Dense.

Regarding our negotiations with a potential joint venture partner in the Brown Dense, the period of exclusivity with a previously announced potential partner has lapsed and, while an agreement may be

reached with that party, we are engaged in discussions with other interested parties on joining with us to work on this promising opportunity. The lack of a joint venture partner will not slow our testing of the Brown Dense exploration program.

In our Denver-Julesburg Basin oil play in eastern Colorado, we re-entered and drilled a 2,000-foot lateral in our second well, the Staner 5-58 #1. We are completing this lateral and have fracture stimulated 5 stages out of a total 16 planned stages. The well started flowback on April 13th and began producing oil on the second day. We will watch the performance of these stages and then complete the remaining 11 stages in June.

In our other New Ventures, in Montana we plan to re-enter an existing vertical well in Sheridan County to test the Bakken and Three Forks unconventional potential in the second quarter.

We continue to lease on new ideas and hope to disclose at least one more of these by year-end.

To close, we remain sharply focused on innovating and adding value for each dollar we invest. I am highly encouraged by the opportunities we have ahead of us in 2013 and I look forward to discussing our progress with you in future quarters.

I will now turn it over to Craig Owen who will discuss our financial results.

Craig Owen–SeniorVice President and  Chief Financial Officer

Thank you, Bill, and good morning.

As Steve has mentioned, we had an exceptional quarter driven by higher production volumes and lower costs. Excluding the unrealized mark-to-market impact of derivative contracts, we reported adjusted net income of $146 million, or $0.42 per share, for the first quarter compared to $106 million, or $0.30 per share, the prior year. Our cash flow from operations (before changes in operating assets and liabilities) was approximately $426 million, a record for discretionary cash flow generated in the first quarter, and up 15% compared to this time last year.

Operating income for our Exploration & Production segment was $176 million, up 53% compared to $115 million in the first quarter of 2012, again primarily due to higher production and lower costs partially offset by a slight decline in realized gas prices.

We realized an average gas price of $3.43 per Mcf during the first quarter, which was down from $3.48 per Mcf in the first quarter of 2012. We currently have 240 Bcf, or approximately 50%, of our remaining 2013 projected natural gas production hedged through fixed price swaps at a weighted average price of $4.71 per MMBtu. We also have 233 Bcf of natural gas swaps in 2014 at an average price of $4.41 per MMBtu. We continue to watch the gas markets and will look for opportunities to add to our hedge position.  Additionally, we added a new line item to our income statement, entitled “Commodity Derivative Income/Loss,” to capture the mark-to-market impact of our derivative contracts that have not been qualified as cash flow hedges, which includes our basis hedges, call options sold for 2015 production and about 182 Bcf of our 2014 fixed price swaps associated with the 2015 call options.

Our cost structure continues to be one of the lowest in our industry, with all-in cash operating costs of approximately $1.18 per Mcfe in the first quarter of 2013, compared to $1.28 per Mcfe last year. That includes our LOE, G&A, net interest expense and taxes.

Lease operating expenses for our E&P segment were $0.81 per Mcfe in the first quarter, down from $0.83 per Mcfe in the first quarter of 2012, primarily due to lower salt water disposal costs associated with the Fayetteville Shale play. Our G&A expenses were $0.21 per Mcfe, down from $0.30 per Mcfe a year ago, and were lower due to decreased information systems costs and adjustments to employee-related costs. These adjustments are not expected to be recurring and we anticipate our G&A costs will be in line with our previously issued guidance of $0.26 - $0.30 per Mcfe for the remainder of the year.  Taxes other than income taxes were also lower at $0.12 per Mcfe, down from $0.13 a year ago. Our full cost pool amortization rate in our E&P segment fell to $1.09 per Mcfe, compared to $1.33 last year. 

Operating income from our Midstream Services segment rose 10% to $76 million during the quarter, primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale plays.

At March 31, 2013, our debt-to-total book capitalization ratio was 36%, essentially flat when compared to the end of 2012, and our liquidity continues to be in great shape with only $35 million borrowed on our $1.5 billion unsecured revolving credit facility at March 31st. We currently expect our debt-to-total book capitalization ratio at the end of 2013 to be approximately 31% to 33% at current strip prices.

In summary, 2013 already looks like it will be a record year for Southwestern Energy – with strong cash flow generation, an excellent balance sheet and a low cost structure, we are ready to deliver even “more” value not only in 2013, but for many years to come.

That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.

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 with 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, 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.

	3 Months Ended March 31,
	2013	2012
	(in thousands)
Net income:
Net income	$ 127,515	$ 107,704
Deduct (add back):
Unrealized gain (loss) on derivative contracts (net of taxes)	(18,473)	1,276
Adjusted net income	$ 145,988	$ 106,428

	3 Months Ended March 31,
	2013	2012
Diluted earnings per share:
Net income per share	$ 0.36	$ 0.31
Deduct (add back):
Unrealized gain (loss) on derivative contracts (net of taxes)	(0.06)	0.01
Adjusted net income per share	$ 0.42	$ 0.30

	3 Months Ended March 31,
	2013	2012
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 372,138	$ 444,663
Deduct (add back):
Change in operating assets and liabilities	(54,114)	73,843
Net cash provided by operating activities before changes  in operating assets and liabilities	$ 426,252	$ 370,820