Southwestern Energy Third Quarter 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, 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 third 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 posted record results in the third quarter. Not only did we set new records for production, Ebitda and cash flow, but each of our operating teams achieved new milestones as well. Our production growth of 19% was driven by our Marcellus Shale properties, where our gross operated production reached the 600 MMcf per day milestone. In addition, the fourth quarter will see the first test on the Marcellus properties we acquired in the second quarter.

 

In the Fayetteville, we continue to be innovative and improvements to our completion techniques led to excellent results in the third quarter. We achieved record average production rates for wells turned to sales during the quarter, and we placed on production two of the play’s highest producing wells to date. This is even more impressive when you consider we are still improving this property even after drilling 3,000+ wells and reaching the milestone of 3 Tcf of gross operated production.

 

In the Brown Dense project, we have drilled our first commercial well and plan to drill and complete 3 more wells by year-end. We are not ready to call this play economic, but we are encouraged with our progress to date.

 

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.  To echo Steve’s comments, we had an excellent quarter which was again driven by our proven industry leading operating capability underpinned by our curiosity and constant focus on delivering “more” to our shareholders.

 

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Our Marcellus Shale properties continued on our planned path of significant growth by reaching a gross operated production rate of over 600 million cubic feet of gas per day in August.  We also added additional firm transport capacity enabling this growth to continue.

 

In the Fayetteville, our focus on constantly improving the value of this asset continues to produce results, as we placed two of the highest-rate wells ever drilled and completed on production during the quarter with IP rates near 10 million cubic feet of gas per day.  In addition, we continued testing the Upper Fayetteville formation and in October we brought on 2 wells producing at the highest rates we have seen to date for Upper Fayetteville wells.  

 

As Steve briefly mentioned, in our Brown Dense play, we have drilled and completed our first economic well, the Sharp vertical well, located in Union Parish, Louisiana.  The well reached a peak rate of 600 barrels per day of 52 API gravity oil and 1.3 million cubic feet per day of 1,240 Btu gas. 

 

After 88 days on production, the well continues to flow at 530 barrels of oil per day and 1.1 million cubic feet per day on a 16/64-inch choke.  I will speak more about our plans in a few minutes.

 

Overall, we completed the third quarter with a 19% growth in our total production and have made a third upward revision to our production guidance for the year.  This is a testimony to the creativity, hard work, dedication and focus of all of our teams on delivering “more” value in all they do.

 

Marcellus Shale

 

To begin with the Marcellus, we placed 22 wells on production during the quarter, which led to net production that was almost 200% greater than compared to a year ago, rising to approximately 45 billion cubic feet per day of gas, up from 15 billion cubic feet per day of gas in the third quarter of 2012.

 

We continue to be pleased with our results as we delineate our acreage in Susquehanna County.  We placed 12 wells on production in the area during the third quarter and gross operated production was 267 million cubic feet per day at September 30 from a total of 61 wells, up from 184 million cubic feet per day of gas at July 1st. 

 

We added another phase of compression in northern Susquehanna County last week which now allows over two-thirds of our wells in that area to produce at higher rates. Additional compression is planned to be placed in-service in the area in the first quarter of 2014.  We are also planning to test more of our acreage in the county as we move north and east to the New York border, which will begin in 2014.

 

In December, we intend to drill our first well in Sullivan County and drilling in Wyoming and Tioga Counties is expected to begin early in 2014.

 

On the gathering side, our midstream company was gathering 344 million cubic feet of gas per day from 89 miles of gathering lines across all of our Marcellus acreage, out of the total 611 million cubic feet of gas per day being produced at September 30.

 

It is well known that basis differentials in the Marcellus area widened dramatically at certain sales points beginning in June and during the entire third quarter.  Our Gas Marketing team did an outstanding job of getting the majority of our gas to high value sales points with better prices during the quarter.  Our ability to move our Marcellus gas to the better-priced and more liquid markets is built on our strategy of securing firm transportation capacity to move our gas out of the area. 

 

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We have just executed an agreement to secure additional firm transportation capacity on Millennium, subject to completing a new interconnect project, beginning in November of 2014 for an additional 150,000 million cubic feet per day.  This increases our total firm transportation capacity out of the basin to approximately 872 million cubic feet per day by year-end 2014 and over 1 Billion cubic feet per day by year-end of 2015.  We will keep you updated as we are able to obtain more firm transportation capacity in order to move our gas to the best-priced areas in the country.

 

We expect to have another year of very strong results in the Marcellus in 2014.  We will be giving more information on our plans for the Marcellus in our capital program update in December.

 

Fayetteville Shale Play

 

In the Fayetteville Shale, we placed 89 operated horizontal wells on production in the third quarter at a record initial production rate of 5.0 million cubic feet of gas per day.  This rate was bolstered by an extremely good September, where we placed on production 31 wells at an average initial rate of 5.4 million cubic feet of gas per day.

 

Results during the quarter included the two strongest wells we’ve drilled since we announced the play in 2004, the Sneed and Ledbetter wells, which achieved peak 24-hour production rates of 10.1 and 9.2 million cubic feet of gas per day, respectively. 

 

As I mentioned earlier, we also had encouraging results from a couple of Upper Fayetteville tests placed on production in early October that achieved peak 24-hour production rates of 6.6 and 6.7 million cubic feet of gas per day, respectively.  We are continuing to evaluate this reservoir and believe that it could provide material additional gas resource to capture over time.

 

Not only did we put on-line some of the largest wells in the play during the quarter which contributed to our highest ever quarterly IP rate in the Fayetteville, but we also are seeing tangible benefits from changes we are making in our completion and flow-back procedures in certain parts of the play that are enhancing early well productivity.

 

We have begun a procedure of “resting” wells for a short period of time, from 10 to 20 days, before we place them on production.  Our results to date have shown that by resting the wells before we place them on production, we are seeing lower produced water volumes and therefore lower water handling costs and higher initial gas volumes.  We have completed a total of 55 tests to date and plan to have around 20 additional wells to place on production in the fourth quarter.

 

It now is a standard procedure on two pilots (Pike and Sturgeon), where historically wells are relatively deeper and have exhibited higher initial water production rates.  Those areas have shown the greatest benefit to date.

 

Our completed well costs were $2.6 million in the third quarter, up from $2.3 million in the second quarter, due to longer laterals and deeper average vertical depths.  Through the first nine months, our average well cost has been $2.3 million per well.  Our vertically integrated services continue to be a significant benefit in lowering our well costs by an average of approximately $380,000 per well in 2013.

 

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New Ventures

 

In New Ventures, we remain encouraged that the work in our Brown Dense exploration program is paying off and believe that the potential value creation from this project could be substantial for us over time.

 

As I mentioned briefly, we have recently drilled and completed our first economic well, the Sharp, which is a vertical well, located in Union Parish, Louisiana.  This well was completed in 3 stages with resin coated proppant and cross linked gel and accessed the entire Brown Dense interval which is about 450 feet thick in this well.  The Sharp Well has since shown a flattening production profile, which is promising. We are encouraged about this result and will continue to watch the shape of its production profile over time.

 

Our next vertical well, the Hollis, was completed with 3 stages and again accessed the entire Brown Dense interval.  The well commenced flow back last week and is still unloading.  Our McMahen vertical well in Columbia County, Arkansas, reached total depth last week and we expect to complete this well with 3 to 4 stages in late-November.  We also spud our Plum Creek vertical test in Union Parish last week with a target vertical depth of 9,500 feet.

 

As we capture and understand the learnings from various technical studies currently underway and our recent wells, in the near term, we will drill a series of vertical wells and apply what we learn from verticals to see if we can unlock more contactable reservoir volume with horizontal wells in the future.  We continue to test not only different completion techniques, but also different theories in each of these wells.

 

While we realize that the results we are reporting to you are only on a few wells with short production histories, we continue to be excited about the potential of the Brown Dense.  We are learning more with each well we drill and are making solid progress on best practices for drilling and completing these wells.  We believe we have moved our understanding and our performance in the play forward and will keep working to unlock this resource and further improve our results.

 

In our Denver-Julesburg Basin oil play in eastern Colorado, our Staner well, which included a 3,400 foot lateral with 10 stages completed, was placed on production in July and reached a peak rate of 146 barrels of oil per day. We will continue to test the Marmaton and Atoka with additional wells to be spud in the first quarter.

 

In the Paradox Basin in Utah, we will continue to test our acreage with additional wells to be drilled in 2014.  We continue to lease acreage in this area and will update everyone on our activity here by next quarter.

 

To close, I am very proud of our results in the third quarter, but more importantly I am proud of the hard work and commitment that all of our teams have exhibited throughout the year.

 

We know that there is more work to be done to keep driving our costs down, while increasing the innovation and the successful execution of every aspect of the project inventories we have before us. 

 

We remain excited about our New Ventures projects and also are focusing on more exploration ideas to initiate next year.  We have much more to look forward to as we enter into 2014.

 

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.

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Our results in the third quarter were excellent, driven by higher production volumes and higher gas prices. Excluding non-cash items, we reported record net income of approximately $180 million, or $0.51 per share, in the third quarter compared to net income of $132 million, or $0.38 per share last year. Cash flow from operations (before changes in operating assets and liabilities) was a record $527 million, up 7% sequentially and up 26% compared to the third quarter of 2012 and also within $15 million of our capital investments for the quarter.

 

Operating income for our Exploration & Production segment was $223 million, compared to $148 million in the third quarter of 2012.

 

We realized an average gas price of $3.60 per Mcf during the third quarter, compared to $3.41 per Mcf last year, and have 84 Bcf of our remaining 2013 projected natural gas production hedged through fixed price swaps at a weighted average price of $4.68 per MMBtu. We also have 233 Bcf of natural gas swaps in 2014 at an average price of $4.41 per MMBtu.

 

As for field differentials, we currently have protected approximately 74 Bcf of our remaining 2013 projected natural 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. This includes approximately 20 Bcf of our expected Marcellus volumes that are protected through year-end at ($0.08) per Mcf. In total, we expect a $0.55 discount to NYMEX for the fourth quarter of 2013, including transportation and fuel charges.

 

Our cash operating costs of approximately $1.25 per Mcfe in the third quarter continue to be a competitive advantage for us. Lease operating expenses for our E&P segment were $0.87 per Mcfe in the third quarter, up from $0.79 per Mcfe last year, primarily due to higher third-party compression and gathering costs in the Marcellus Shale, partially offset by lower salt water disposal costs in the Fayetteville Shale. Our G&A expenses were $0.24 per Mcfe, up from $0.21 per Mcfe a year ago, due to higher personnel costs. Taxes other than income taxes were at $0.09 per Mcfe for both periods and our full cost pool amortization rate fell to $1.07 per Mcfe, compared to $1.30 per Mcfe last year. 

 

Operating income from our Midstream Services segment for the quarter was up 15% to approximately $87 million compared to last year.

 

At September 30, our debt-to-total book capitalization ratio was 35%, which is flat when compared to the end of 2012, and our liquidity continues to be in excellent shape. We currently expect our debt-to-total book capitalization ratio at the end of 2013 to be approximately 34% to 36%.

 

Looking ahead to the fourth quarter, the combination of another quarter of strong production and higher gas prices compared to last year points toward more records to be achieved by year-end. In addition, we expect to provide our initial outlook for our 2014 capital program, production and expenses in early-to-mid December.

 

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

 

 

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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 September 30, 2013 and 2012, and 3 months ended June 30, 2013. 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. 

 

 

 

 

 

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