Southwestern Energy Fourth Quarter and Year-End 2012 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, 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 fourth quarter and year-end 2012 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.

Our goal every year is to deliver more to our investors than our competition can.  Internally, we call this “V+.”  2012 was another in the long string of years where we have set new records, developed new efficiencies and expanded both our producing areas and our New Ventures footprint.  Almost every day brought new challenges and I am proud to state many of those challenges were converted to opportunities through the innovation and hard work of SWN’s staff. 

Our production grew by 13%, as results from our wells in the Fayetteville Shale improved and our Marcellus production has begun to ramp dramatically. We also recorded our second-highest cash flow ever, as we made meaningful progress in lowering our cash costs during 2012 and the cash flow growth from our Midstream business continued its strong performance.

We began testing ideas in the Bakken in Montana and the Marmaton in Colorado and we reached a new milestone in the Brown Dense.  During the past several months it has contributed to some of those daily challenges but we are beginning to see a glimpse of how the Brown Dense might be successful and are in the final stages of signing up a partner to help us try to reach commerciality.

All indications are that 2013 will continue the string of adding Value+.  We will drive down days and costs and ramp up production.  But we will also continue to add more value through new exploration ideas, new ways to approach how we work and new ways we enhance the communities where we work. 

I will now turn the call over to Bill for more details on some of the Value+ in our operations and then to Craig for a recap of our strong financial position. 

Bill Way, Executive Vice President and Chief Operating Officer 

Thank you Steve, and good morning everyone.  To echo Steve’s comments, and reflecting on the extraordinary efforts of our outstanding team of industry professionals, the Company achieved several major milestones and accomplishments during the year which I want to share with you.

Among these, we expanded and advanced the Company’s prospective New Ventures opportunities including acquiring new acreage and commencing testing in several new plays in addition to the nearly 495,000 net acres of undisclosed ventures in our portfolio. 

We grew our production to a new record of 565 Bcfe in 2012, which was up 13% compared to 2011 results.  Our growth was driven by our two core operating areas.  In our Fayetteville Shale play, we grew our production by 11% to 485 Bcf versus 2011 results. 

From our efforts to grow our Marcellus business, we more than doubled our production from 23 Bcf in 2011 to 54 Bcf in 2012 as we expanded our development in the play to all four acreage areas.  This growth more than offset the decline in our Ark-La-Tex production which included a reduction due to the sale of our Overton field last year.

We continued to expand our Midstream business as we enter new producing areas.

We also reduced our production expenses and general and administrative expenses by $.05/mcfe across the company.

We booked 919 Bcfe of reserves in 2012 and invested $1.9 billion.  The 33% year over year decrease in the natural gas price decreased our proved reserves to approximately 4.0 Tcfe from 5.9 Tcfe in 2011.  As gas prices rise from the $2.76 per Mcf price that was used for 2012, we know that many of the reserves that were written off at that price will naturally come back on our books over time.

Our strong focus on health, safety and the environment resulted in continued improvement in HS&E performance.

Fayetteville Shale Play

In the Fayetteville Shale, we placed 493 operated horizontal wells on production in 2012, resulting in gross operated production increasing from approximately 1.9 Bcf of gas per day at the beginning of the year to 2.1 Bcf per day of gas at the end of the year. 

Total proved reserves booked in the Fayetteville were approximately 3.0 Tcf, down from 5.1 Tcf at the end of 2011. Again, downward price revisions were the main driver of our decline in reserves.  Our average PUD well is 2.8 Bcf in 2012 compared to 2.4 Bcf in 2011. 

Our operational efficiencies, driven in part by our vertical services integration, continue to improve in the Fayetteville Shale, as our operated horizontal wells had an average completed well cost of $2.5 million per well, average horizontal lateral length of 4,833 feet and average time to drill to total depth of just 6.7 days from re-entry to re-entry.  This compares to a well cost of $2.8 million with approximately the same lateral length that was drilled in about 8 days in 2011.

We also placed 139 wells of our total 493 wells on production during 2012 that were drilled in 5 days or less.  In total, we have drilled 243 wells to date in 5 days or less.

We will continue to work to drive our costs lower and expect that our vertical integration and two newly activated SWN frac crews will make another noticeable positive impact to our well costs in 2013.

We also saw higher average production on a per well basis during 2012 as a result of the optimization efforts on our drilling portfolio.  Our average initial producing rates set new records at approximately 3.6 million cubic feet per day compared to last year’s 3.3 million cubic feet average rate. 

In the fourth quarter of 2012, we set a new record as our average rate approached 4.0 million cubic feet of gas per day.

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 1,852 miles of gathering lines in the field, compared to gathering approximately 2.1 Bcf per day a year ago.

Marcellus Shale

In our Marcellus Shale operation in Pennsylvania, we more than doubled our total proved reserves in 2012 to 816 Bcf, up from 342 Bcf booked at the end of 2011.  Our average PUD well is 7.6 Bcf in 2012, compared to 7.5 Bcf in 2011.

At December 31st, we had a total of 72 wells on production including the initial wells in our Range and Lycoming producing areas which were first brought on production in the fourth quarter.  As I mentioned before, we are now producing from all four of our core producing areas in the Marcellus.  We also have an additional 84 wells in progress in the Marcellus.

Our producing wells include 48 wells located in Bradford County, 4 in Lycoming County and 20 in Susquehanna County.  Of the 84 wells in progress at year-end, 33 were either waiting on completion or waiting to be placed to sales, including 5 in Bradford County, 4 in Lycoming County and 24 in Susquehanna County.

Wells in our Range area where we were waiting on pipeline infrastructure are performing as expected.  Our latest 4 wells on one pad in Lycoming County had IP’s ranging from 9-12 MMcf of gas per day.

Our operated horizontal wells had an average completed well cost of $6.1 million per well, average horizontal lateral length of 4,070 feet and an average of 12 fracture stimulation stages in 2012.  This compares to an average completed well cost of $7.0 million per well, average horizontal lateral length of 4,223 feet and an average of 14 fracture stimulation stages in 2011.

In Susquehanna County, the southern portion of the Bluestone Pipeline was placed into service into TGP 300 on November 28th and the northern portion of the pipeline is expected to be placed into service into the Millennium line in late first quarter.  We also expect compression in our Range Trust to be operating by mid-year, as currently we continue to produce against pipeline pressures in excess of 1,000 psi.

We are continuing to ramp up our Marcellus business in line with available gas transportation infrastructure.  We expect our gross operated production to increase dramatically from our Marcellus properties throughout 2013, from approximately 300 million cubic feet of gas per day at December 31st to over 500 million cubic feet of gas per day by the end of the year.

New Ventures

Moving to our New Ventures, at December 31st we held 3.8 million net undeveloped acres, of which 2.5 million net acres were located in New Brunswick, Canada and the remaining approximately 1.3 million net acres were located in the U.S.

In New Brunswick, we received two one-year extensions to our exploration license agreements in December which extended our license to search until March 31, 2015.  We have also applied for an additional one-year extension that would extend our exploration license agreements until March 31, 2016, if granted by the Province.  In 2013, we intend to acquire approximately 130 additional miles of 2-D seismic data in New Brunswick with first drilling scheduled for some time in 2014.

In February, we reached a tentative agreement for a joint venture in our Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana that includes cash up front as well as a 3 year term carry on accelerated investment activity.  Our plan includes more active drilling program in the Brown Dense in 2013.

To date in the Brown Dense, we have drilled and completed 6 wells.  Each successive well has shown an increase in initial flow rate.  Our latest well, the Doles well, located in Union Parish had an initial flow rate of 435 barrels of  55-57 degree condensate and more than 2.5 million cubic feet per day of 1,250 Btu gas.  After flowing for more than 90 days, the Doles well exhibits producing behaviors similar to the BML well.

We have now spudded our seventh well, the Dean horizontal well located in Union Parish.  We plan to drill and complete a 3,000 foot horizontal lateral with initial results expected in the second quarter.  This well will advance our further understanding of frac geometry and appropriate landing point as well as cost performance.  We are learning more about the play with each successive well and we are focused on analyzing various methods to optimize our fracture stimulation with the focus on increasing reservoir contact area. 

Our results along our path to commerciality continue to progress and we continue to believe that the “size of the prize” is significant.  We remain encouraged about this play.  I look forward to updating you on our efforts to bring this idea to commerciality in the coming months.

In our Denver-Julesburg Basin oil play in eastern Colorado, we have leased approximately 302,000 net acres and have tested 2 wells in the area.  Our first well encountered an oil cut of around 5% which was lower than we expected and is currently shut-in. However, our second well, the Staner, tested 7 different intervals and we encountered an oil cut of over 40% in the vertical portion of the Marmaton.  We have re-entered the Staner and are currently drilling a 3,400-foot lateral in the Marmaton.  We plan to complete this well during the second quarter of 2013.

In 2012, we began production from our first test well targeting the Bakken formation in Sheridan County, Montana.  This well achieved a peak rate of 171 barrels of oil per day and has been producing for over 4 ½ months.  We continue to monitor the production decline in this well, in addition to watching the activity around us, as there will be several more well results from other operators in the area over the next 6 months.  We plan to spud our second well in Sheridan County late in the 2nd quarter targeting the Three Forks objective.

Finally, among the several new plays we entered in 2012, we began accumulating acreage in the Paradox Basin in Utah.  We continue to lease in the area and this is all we plan to say about our idea there, at this time.

We remain sharply focused on adding value for each dollar we invest and are very excited about the opportunities that lie ahead of us in 2013.  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.

As Steve has mentioned, our growth in production and low cost structure were strong but did not fully overcome the impact of low natural gas prices on our earnings and cash flow. Excluding the non-cash ceiling test impairments and the mark-to-market impact of derivative contracts, we reported net income of $485 million, or $1.39 per share, for the calendar year compared to $638 million, or $1.82 per share, the prior year. Our cash flow from operations (before changes in operating assets and liabilities) was approximately $1.6 billion, the second highest level in our history, but down 9% compared to 2011 due to lower gas prices. 

Operating income for our Exploration & Production segment was $528 million, excluding the non-cash items, compared to $825 million in 2011. For the year, we realized an average gas price of $3.44 per Mcf, which was down 18% from $4.19 per Mcf in 2011. 

We currently have 185 Bcf, or approximately 29%, of our 2013 projected natural gas production hedged through fixed price swaps at a weighted average price of $5.06 per MMBtu. We also have added 55 Bcf of natural gas swaps in 2014 at an average price of $4.43 per MMBtu. Our hedge position, combined with the cash flow generated by our Midstream gathering business, provides protection on approximately 50% of our total expected cash flow for 2013. 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 hedge position.

We are proud that we were able to keep our cash costs very low in 2012 and our cost structure continues to be one of the lowest in our industry, with all-in cash operating costs of approximately $1.20 per Mcfe in 2012, compared to $1.24 per Mcfe in 2011. That includes our LOE, G&A, net interest expense and taxes.

Lease operating expenses for our E&P segment were $0.80 per Mcfe in 2012, down from $0.84 per Mcfe in 2011, primarily due to lower compression and salt water disposal costs associated with the Fayetteville Shale play. Our G&A expenses were $0.26 per Mcfe for the year, down from $0.27 per Mcfe in 2011, and were lower due to decreased personnel costs per unit of production. Taxes other than income taxes were $0.10 per Mcfe in 2012, down from $0.11 in 2011. The full cost pool amortization rate in our E&P segment increased to $1.31 per Mcfe, compared to $1.30 last year. 

Operating income from our Midstream Services segment rose 19% to $294 million in 2012 and EBITDA for the segment was $339 million, also up 19%. The increase was primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale plays.

We invested approximately $2.1 billion in 2012 and currently plan to invest approximately $2.0 billion in 2013. At December 31, 2012, our debt-to-total book capitalization ratio was 35%, up from 25% at the end of 2011, driven by our non-cash ceiling test impairments. Additionally, our total debt to trailing EBITDA ratio was about 1.0 times. Our liquidity continues to be in excellent shape, as we had nothing drawn on our revolving credit facility at year-end 2012 and we also had $62 million of cash and restricted cash on our books. We currently expect our debt-to-total book capitalization ratio at the end of 2013 to be approximately 34% to 36%.

In summary, while we were not able to entirely avoid the impact of over a 30% drop in Nymex gas prices, we generated strong cash flow, were able to keep our costs extremely low and exited the year in great shape with regards to our balance sheet and liquidity. To echo Steve’s comments, we look forward to 2013 and believe the combination of our Fayetteville and Marcellus assets, along with our New Ventures ideas, will provide Southwestern with the ability to add significant value 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 and twelve months ended December 31, 2012 and December 31, 2011. 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.