Exhibit 99.1

Southwestern Energy Fourth Quarter and Full Year 2013 Earnings 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, Executive 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 fourth quarter and year-end 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.

2013 was a record-setting year for Southwestern Energy. Our pursuit of providing Value+ for our shareholders was never more apparent. Not only did we achieve new levels of net income, EBITDA, cash flow, production and reserves, but we did it while keeping costs low. Fayetteville records were set through improvements to our completion techniques and we continued expansion into new areas in the Marcellus while moving new concepts and ideas forward. I am very proud of the efforts of all of our employees in 2013 and am certain you will see even more delivered in 2014.

Bill and Craig will speak more about these records and new ideas in a few minutes. I would like to address a few general items. Let’s start with the Brown Dense. As you may remember, last quarter we discussed our first commercial well in the Brown Dense and we also discussed the many things that needed to happen for us to accelerate our investments in this project. Since then we have drilled 5 wells. Three of these were drilled to test the geologic and volatile liquids limits of our acreage in an effort to determine how to respond to potential lease expirations and renewals over the next few years. It is becoming clearer that the best production will be in the high pressure cell first encountered in our third well and extends at least 12 miles through our commercial well, the Sharp 22-22-1. We are currently testing the first offset to the Sharp well and plan to fracture stimulate another offset well in March so we will better be able to discuss the details and what it means to this play during our teleconference in April.

The second general issue concerns the gas price in northeast Pennsylvania. Southwestern Energy’s strategy in both the Fayetteville and Marcellus has been to purchase firm capacity in an effort to contact several liquid sales points and reduce the possibility of large gas price basis issues. As you will see in the earnings release and the discussion by Bill and Craig, our firm capacity along with marketing opportunities have served us well in both the fourth quarter of 2013 and early 2014. From our perspective these are the side benefits of a much broader and longer term strategy. We knew there would be short term volatility in price as the transportation system was maturing in the northeast and we

also know there is a high probability we will be drilling 10 years from now on our acreage but we can only guess today at where the gas will be needed most at that time. We continue to believe the right strategy to maximize price throughout the life of our projects is to create as many outlets to as many major markets as is economically feasible. We have accomplished that in the Fayetteville and need only a few more pieces to fill out the Marcellus.

Gas markets outside of the Marcellus have also been making headlines. Before I turn the call over to Bill and Craig for an update on our operations and financial position, I want to leave you with my thoughts on the overall natural gas markets.

While we have enjoyed the higher gas prices created by a cold winter, I feel the same way that I did in the winter of 2012. We had just come through what was reported to be “the warmest winter in the northeastern US in over 80 years.” The outcome was low draw downs of storage and earlier than normal injections – which resulted in gas prices breaking under $2.00 in April of that year.

My point is this: One season of cold weather or one season of warm weather does not make or break gas prices that Southwestern Energy uses to make our decisions and it does not drive our company or the great year 2014 is shaping up to be.

Certainly the future looks brighter than the past few years. The industry will need to increase supply by approximately 4 Bcf per day over 2013 to re-fill storage to acceptable levels and we were already seeing the gas supply and demand situation improving. Both of those facts, allow me to feel more comfortable that the NYMEX price has a good chance to average above $4.00 for the next several years but I still believe a significant amount of new drilling can and will be done as the price approaches $5.00. So, while we are and will be enjoying the additional cash flow from the prices we’ve seen so far in 2014, we have built our company to thrive in a much lower price environment. You can see that in our 2013 records established in a year when the NYMEX price averaged $3.67 per MMBtu.

With that, I will now turn the teleconference over to Bill for an update on our 2013 results.

Bill Way, Executive Vice President and Chief Operating Officer

Thank you, Steve, and good morning everyone. To further elaborate on Steve’s comments, 2013 was an exceptional year for Southwestern Energy and I am very proud of the innovation, hard work and commitment that all of our teams demonstrated throughout the year.

I’d like to share with you the list of milestones that we were able to achieve during the year, all of which are truly extraordinary, including several new company records:

In 2013 we set a new record for production of 657 billion cubic feet equivalent, which was up 16% compared to last year.

With our increased production, in the fourth quarter, Southwestern Energy became the 4th largest producer of natural gas in the Lower 48 United States; and just last week we achieved a new milestone of 2 billion cubic feet equivalent of net production per day by the company,

We set a new record for proved reserves of approximately 7 trillion cubic feet equivalent, which was up 74% compared to last year,

We achieved the lowest finding cost in company history at $0.56 per Mcfe and the third highest reserve replacement in company history,

In the Marcellus Shale, our production from the area nearly tripled while our reserves were more than double compared to last year. This translates to gross operated production having reached nearly 700 million cubic feet of gas per day at year-end. I would note here that we eclipsed 750 million cubic feet of gas per day earlier this month,

In the Fayetteville Shale, we reached the milestone of 3 trillion cubic feet of cumulative production from our operated wells since the inception of the play; our reserves in the area were also up 60% compared to last year; and for the year we achieved both the highest average initial production rate per well and the lowest average completed well cost in our history,

In Exploration, we continued to acquire new acreage and tested several existing and new plays and have more ideas to explore on the horizon,

And finally, our Midstream Services segment posted the highest EBITDA in its history and made very good progress on adding additional firm transportation out of Marcellus to facilitate the continued growth of our production in our expanded acreage footprint.

These accomplishments, along with many other smaller victories that are too numerous to count, give me a great amount of pride in our teams.

Marcellus Shale

In the Marcellus Shale, we placed a total of 100 wells on production during the year, resulting in production from the area of 151 billion cubic feet in 2013, up 181% from 54 billion cubic feet in 2012.

Gross operated production in the Marcellus Shale was approximately 700 million cubic feet per day at the end of 2013 compared to approximately 300 million cubic feet per day at the end of 2012.

Total proved net reserves in the Marcellus Shale grew by 141% to approximately 2 trillion cubic feet in 2013, compared to 816 billion cubic feet in 2012.

To comment briefly on our reserves in the Marcellus, we are very encouraged about the potential size of the resource we have captured in our Pennsylvania acreage position.

We have been drilling in Bradford County for over three years now. Our Blaine-Hoyd well in southern Bradford County, which we brought on line last year had a peak 24-hour rate of 24 million cubic feet of gas per day, was an unbounded, first well in a section and is currently booked at 22.6 Bcf.

Based on production history, we feel confident of the resource we have in place in Bradford County. We believe that average EURs in that area should be in the 12 to 16 billion cubic feet per well range for a typical ±5000 foot lateral with 1000 foot well spacing.

Today, we currently have booked gross proven reserves averaging 8.7 billion cubic feet per well for PDP wells and 7.2 billion cubic feet per well for PUD wells.

In our Range area in Susquehanna County, we have been producing in our core area for a little over a year. Notable well results in 2013 include our Seamens well located in northern Susquehanna County which was placed on production in November 2013 and reached a peak 24-hour initial production rate of 32 million cubic feet of gas per day.

While we still need some time to understand all of our acreage in Susquehanna County, we are very encouraged with what we have de-risked to date, which is about 40,000 net acres.

We believe that EURs in this area should be similar to our Bradford County wells on average, in other words in the 10 to 16 billion cubic feet per well range for a typical ±5000 foot lateral with 1000 foot well spacing. We have PDP wells in the Susquehanna County area on our books at around 7 billion cubic feet per well. With additional production history, it is likely that you will see upward reserve revisions in this area in the future as well.

All comments on resources and reserves apply to our Lower Marcellus horizontal wells only. We will begin testing the Upper Marcellus in our Bradford County area during 2014.

On the new acreage we added to our Marcellus position in 2013, we have drilled two vertical science wells, one in Sullivan County and one in Wyoming County. We will drill a few more vertical science wells in both counties to further test the area. We are encouraged with what we have seen so far to date.

On the gathering side in Pennsylvania, our Midstream Company was gathering 366 million cubic feet of gas per day from 90 miles of gathering lines across all of our Marcellus acreage at year-end. Since inception, we have invested nearly $200 million in our gathering systems in Pennsylvania and in 2013 generated about $30 million of cash flow.

We added 16,560 horsepower of compression in the Marcellus in 2013 and look to add a similar amount in 2014, with new compression planned to be added in both in our Bradford and Susquehanna County areas. We will continue to add compression throughout 2014 commensurate with our planned production growth.

Over the past six months, there has been a lot of discussion in the marketplace about the expected production growth from the northeast corner of Pennsylvania, and the impact that this has had on current firm transportation capacity and field prices in the area.

Our Gas Marketing team has done an outstanding job of contracting additional firm transportation arrangements which gives us access to the better price points in the area.

In total, we added over 300 million cubic feet of gas per day of firm transportation agreements out of the basin in 2013 enabling us to reach and sustain 1 billion cubic feet per day by the end of the year.

Our long term average transportation demand rate is approximately $0.37 per Mcf. We have protected approximately 58% our Marcellus gas production in 2014 with financial and physical sales arrangements at approximately $0.13 per Mcf lower than NYMEX, exclusive of our transportation cost.

Our strategy of leading with firm transportation has paid off and continues to allow us to ramp our production from the area significantly over the next few years.

We expect to have another year of very strong results in the Marcellus in 2014. Our gross operated production is projected to increase to over 900 million cubic feet of gas per day by the end of 2014 and we will continue to work toward finding additional marketing opportunities for our gas as the year progresses.

Fayetteville Shale

In the Fayetteville Shale, we placed 414 operated horizontal wells on production in 2013, resulting in production of 486 billion cubic feet in 2013. Importantly, we achieved this production last year with almost 80 fewer wells as compared to the previous year when we placed 493 wells on production, which is a testimony to our growing capital efficiency. Total proved reserves grew by 60% to 4.8 trillion cubic feet, compared to 3.0 Tcf in 2012.

In 2013, our relentless focus on delivering more showed very encouraging results as we began to make several changes to our completion and flow-back procedures in certain parts of the play which had a meaningful impact to early production histories in several of our wells.

By experimenting with our completions and flowback configurations, “resting” the wells for a short period of time before we place them on production and further optimizing surface facilities, we have seen a significant increase in initial gas production rates with lower volumes of produced flowback water.

Initial production rates in the third and fourth quarters were the highest in Company history, with our fourth quarter average IP rate setting a new record of 4.9 million cubic feet per day, along with record 30th-day and 60th-day rates of 2.86 million cubic feet per day and 2.58 million cubic feet per day, respectively, for wells placed on production in the quarter. Nine of the top ten highest-rate wells in the history of the Fayetteville Shale were drilled and placed on production during the third and fourth quarters of 2013. We are currently examining additional opportunities across the play to perform these modified completion techniques in 2014.

We continue to work to drive our costs lower as well and in 2013 we set a new record for the lowest average completed well cost in our history of $2.4 million per well. Our vertical integration in the Fayetteville, which includes drilling rigs, our company-owned sand plant, our two SWN owned frac crews and other field services, provided an average savings of approximately $390,000 per well. Our vertical integration is a key component of our industry leading efficiency.

On the Midstream side, our gas gathering business in the Fayetteville Shale continued to perform well and at December 31st was gathering approximately 2.3 billion cubic feet of natural gas per day from 1,947 miles of gathering lines. Our cumulative total investment in our gathering systems in the Fayetteville is nearly $1.1 billion to date; it is paid out, and in 2013 generated about $310 million of cash flow.

Exploration

Moving to our Exploration group, at December 31st we held 4.0 million net acres representing several potential new projects for us, of which 2.5 million net acres were located in New Brunswick, Canada, and 460,000 net acres are in our Brown Dense project.

While Steve has already commented on our Brown Dense project, in our Denver-Julesburg Basin oil play in eastern Colorado, we have leased approximately 302,000 net acres and have tested two wells targeting the Marmaton and Atoka formations in the area. We plan to drill an additional vertical well in the area during the second quarter of 2014.

We will begin drilling on two to three additional Exploration ideas in 2014. We will keep you posted on our progress when the timing is appropriate.

In closing, I again would like to thank all of them for a job well done. While we are extremely proud of our accomplishments in 2013, we believe that 2014 will be even better. We are very excited about the opportunities that lie ahead.

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

Craig Owen, Senior Vice President and Chief Financial Officer

Thank you, Bill, and good morning.

Our results in 2013 were excellent and driven by higher production volumes and higher realized gas prices over 2012 and our continued focus on lowering costs. Excluding certain non-cash items, we reported record net income in 2013 of approximately $704 million, or $2.00 per diluted share, compared to $487 million, or $1.39 per diluted share in 2012. Net cash provided by operating activities (before changes in operating assets and liabilities) was a Company record at $2 billion, up 24% compared to 2012. In the fourth quarter, our net cash provided by operating activities of $538 million exceeded our capital investments by $59 million.

Operating income for our Exploration & Production segment was $879 million compared to $543 million, excluding the non-cash ceiling test impairment, in 2012. For the year, we realized an average gas price including hedges of $3.65 per Mcf, which was up from $3.44 per Mcf in 2012.

We currently have 456 Bcf, or approximately 61%, of our 2014 projected natural gas production hedged through fixed price swaps at a weighted average price of $4.34 per MMBtu. We have also recently added 120 Bcf of natural gas swaps in 2015 at an average price of $4.40 per MMBtu. In the Marcellus, we estimate that our January and February realized price, excluding hedges, is about $0.45 to $0.50 above NYMEX. Our hedge position, combined with the cash flow generated from our Midstream gathering business, provides protection on approximately 70% of our total expected cash flow for 2014. Our detailed hedge position is included in our Form 10-K filed yesterday and we continue to monitor the gas markets and will be looking for opportunities to add to our 2015 hedge position.

We are proud that we were able to keep our cash costs very low in 2013 and our cost structure continues to be one of the lowest in our industry, with all-in cash operating costs of approximately $1.25 per Mcfe in 2013, compared to $1.20 per Mcfe in 2012. That includes our LOE, G&A, net interest expense and taxes.

Lease operating expenses for our E&P segment were $0.86 per Mcfe in 2013, up from $0.80 per Mcfe in 2012, primarily due to increased gathering and compression costs associated with the Marcellus Shale, partially offset by decreased salt water disposal costs associated with the Fayetteville Shale. Our G&A expenses were $0.24 per Mcfe for the year, down from $0.26 per Mcfe in 2012, and were lower due to decreased personnel costs per unit of production. Taxes other than income taxes were flat at $0.10 per Mcfe in 2013 and 2012. The full cost pool amortization rate in our E&P segment decreased to $1.08 per Mcfe, compared to $1.31 per Mcfe last year.

Operating income from our Midstream Services segment rose 11% to $325 million in 2013 and EBITDA for the segment was $376 million, also up 11% and, as Bill mentioned, is a Company record. These increases were primarily due to the increase in gathering and marketing volumes from our Marcellus and Fayetteville assets.

We invested approximately $2.2 billion in 2013 and currently plan to invest approximately $2.3 billion in 2014. At December 31, 2013, our debt-to-total book capitalization ratio was 35%, flat from 2012. Additionally, our total debt to trailing EBITDA ratio was about 1.0 times. Our liquidity continues to be in excellent shape, as we had $283 million drawn on our $2 billion dollar revolving credit facility at year-end 2013 and we also had $23 million of cash on our books. We currently expect our debt-to-total book capitalization ratio at the end of 2014 to range from 31 to 33 percent.

Looking ahead to 2014, more records are within sight due to the combination of increased production, our low cost structure and what is shaping up to be another year of higher realized gas prices.

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 and twelve months ended December 31, 2013 and 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.


	12 Months Ended Dec. 31,
	2013	2012
	(in thousands)
Net income (loss):
Net income (loss)	$ 703,503	$ (707,064)
Add back:
Impairment of natural gas and oil properties (net of taxes)	--	1,192,412
Adjustments due to discrete tax items(1)	12,997	--
(Gain) loss on certain derivative contracts (net of taxes)	(12,636)	1,324
Adjusted net income	$ 703,864	$ 486,672


	12 Months Ended Dec. 31,
	2013	2012

Diluted earnings per share:
Diluted earnings (loss) per share	$ 2.00	$ (2.03)
Add back (deduct):
Impairment of natural gas and oil properties (net of taxes)	--	3.42
Adjustments due to discrete tax items(1)	0.04	--
Gain on certain derivative contracts (net of taxes)	(0.04)	--
Adjusted diluted earnings per share	$ 2.00	$ 1.39


	3 Months Ended Dec. 31, 2013
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$531,010
Add back (deduct):
Change in operating assets and liabilities	$ 7,244
Net cash provided by operating activities before changes in operating assets and liabilities	$538,254

	12 Months Ended Dec. 31,
	2013	2012
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 1,908,528	$ 1,653,942
Add back (deduct):
Change in operating assets and liabilities	75,272	(55,060)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 1,983,800	$ 1,598,882


	12 Months Ended Dec. 31,
	2013	2012
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ 878,701	$ (1,396,261)
Add back:
Impairment of natural gas and oil properties	--	1,939,734
Adjusted E&P segment operating income	$ 878,701	$ 543,473


	12 Months Ended Dec. 31,
	2013	2012
	(in thousands)
Midstream Adjusted EBITDA:
Net income (loss)	$ 196,072	$ 175,570
Add back (deduct):
Depreciation, depletion and amortization expense	50,940	44,395
Gain on derivatives, net of settlement	(480)	--
Net interest expense	10,619	14,341
Provision for income taxes	119,223	104,522
Adjusted Midstream EBITDA:	$ 376,374	$ 338,828