Southwestern Energy Second 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 second 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.

 

SWN had an excellent quarter. The combination of higher production and higher realized gas prices resulted in records for adjusted earnings, EBITDA and cash flow in the second quarter. Our production growth of 17% was primarily fueled by strong well performance from our Marcellus Shale properties combined with more wells placed on production. As a result, we have increased our production guidance for the second time this year. Additionally, our well counts and capital investments for the year have also increased due to our recent acquisition and planned drilling on it, as well as faster drilling times and increased capital efficiency.

 

SWN’s theme for 2013 is about delivering “more” to our shareholders, our stakeholders and the communities we live and work in. In the Fayetteville Shale, we have decided to keep 8 rigs running all year and have increased our capital budget and well counts.  The net result is not only additional production, but the Fayetteville Shale now will provide nearly $100 million in free cash flow back to the company, compared to being roughly net cash flow neutral at the beginning of the year. This is a great example of delivering “more.”

 

In the Marcellus, we have learned much more about the productivity of our wells in northern Susquehanna County and our production ramp out of the area has been tremendous, growing from zero to over 180 MMcf per day in just seven months. The wells tested to date have only effectively developed approximately 5% of our total Range Trust acreage, but because of the geographic extent covered we believe we have already de-risked approximately 50% of our total position in the area, especially to the north and east. There is more to learn, and more to come, from this area and the other counties as we start exploring some of the new acreage we purchased earlier this year. The Marcellus is obviously delivering “more.”

 

Almost every year in the heat of the Summer, the debate rages about the future of the price of gas. This year, the gap between supply and demand continues to narrow, so we remain encouraged about a $4.00+ gas price long term.

 

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Keep in mind, gas price does not drive our success. As we proved in 2012, our business model can generate returns in a low gas price environment. You can be sure we will always be focused on disciplined investing, keeping our costs low and on delivering more value from our business. 

 

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.  The execution of our drilling and completions programs in our Marcellus and Fayetteville areas has resulted in record production and has set the stage for a good year for Southwestern Energy in 2013. The production performance from both areas has been outstanding and I want to personally thank our Fayetteville and Pennsylvania teams for a terrific job! 

 

Overall, our production in the second quarter grew by 17% over last year, fueled largely by faster drilling times in the Fayetteville and strong well results and increased activity in Pennsylvania. As a result of this success, we have increased our production guidance for the remainder of the year. Further, we have increased our capital budget which includes our acreage acquisition in Pennsylvania which was closed in the second quarter, additional drilling activity due to faster drilling times and greater efficiencies and capital for our E&P services group. As a result, our planned well counts will increase by approximately 70 wells in the Fayetteville and 15 wells in the Marcellus.

 

Marcellus Shale

 

To begin with the Marcellus, we placed 37 wells on production compared to 21 wells in the first quarter. As a result, our gross operated production that had reached 400 million cubic feet of gas per day in mid-April further increased to 500 million cubic feet of gas per day by mid-June. Net production for the quarter was 3 times greater when compared to a year ago, rising to approximately 34 Bcf up from 10 Bcf in the second quarter of 2012.

 

Our Marcellus production will continue to grow in line with available gas transportation infrastructure.  At this time, we currently have agreements in place that allow us to transport over 800 million cubic feet of gas per day out of the area by 2015. We are pursuing opportunities for long-term access to additional firm takeaway capacity out the basin and will keep you updated as things progress for us in this area.

 

In keeping with our plans for the area, we announced yesterday that we have entered into agreements with subsidiaries of DTE Pipeline Company which provide for additional firm capacity to both the Millennium and Tennessee Gas Pipelines on the Bluestone Gathering system in Susquehanna County. This additional capacity further strengthens our ability to move our Marcellus gas to liquid markets from the area. We also added 103 million cubic feet per day of additional firm transportation capacity on various long-haul pipes comprised of a mixture of firm transport and short and long term sales.

 

The delineation of our Range Trust area in northern Susquehanna County continues to provide strong results since we first put wells in the area on production in late November.  Eighteen wells were brought on production in the area during the second quarter, helping to further delineate the acreage to the east and north. In just seven months, gross operated production has increased from zero to approximately 184 MMcf per day at July 1st from a total of 40 wells.

 

As a follow-up on our Blaine-Hoyd well in southern Bradford County that we announced last quarter, the production from this well continues to be very strong. As a reminder, this well had 32 stages in the completion and longer CLAT of over 6,500 feet. After 90 days, this well was still producing approximately 16 MMcf per day and had cumulative production of 1.5 Bcf for the second quarter. Earlier this week, the well was still producing approximately 15 MMcf per day.

 

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We continue to experiment with our fracture stimulations, lateral lengths and flow techniques, further optimizing our well performance, and believe we are getting closer to conclusions on how to best stimulate these wells. Wells placed to sales in the first six months of 2013 have averaged 17 stages per well, compared to 12 stages in 2012, while average lateral lengths have been approximately 4,700 feet this year, compared to roughly 4,100 feet last year. Meanwhile, completed wells costs have declined to $6.6 million per well in the second quarter compared to a little over $7.0 million per well in the first quarter.

 

On the midstream side, total gathered volume in the Marcellus was approximately 503 million cubic feet of natural gas per day from 167 miles of gathering lines in the field at June 30; half of which are SWN owned and are gathering 300 million cubic feet per day.  We also added first compression to the Range area in late-June with another phase of compression scheduled to be placed in-service in October. Additional compression will be placed in-service in Greenzweig yesterday, and first compression at Lycoming is planned to come on-line later this year. As more compression is installed in these areas, our wells will not have to compete as much against higher line pressures and can then produce at higher rates.

 

We have also closed on the previously-announced acquisition of approximately 162,000 net acres near our existing acreage position in Pennsylvania in May. We have included $50 million dollars in our revised capital budget for drilling, lease renewals, participation in wells operated by others and seismic on this new acreage.     

 

Fayetteville Shale Play

 

In the Fayetteville Shale, we placed 126 operated horizontal wells on production in the first quarter at an average completed well cost of $2.3 million per well. Our completed well costs were up from $2.1 million in the first quarter due to longer laterals and deeper average vertical depths. This marks the first quarter that our laterals have averaged over 5,000 feet since the inception of the play.

 

We continue to drill wells across the play and the resulting economic value from our wells in the second quarter continued to be enhanced by our vertically integrated services and further efficiencies continue to be a significant benefit in driving our costs lower.

 

Initial production rates from wells drilled during the second quarter returned to trend and averaged 3.6 million cubic feet of gas per day. For wells already brought on-line in July, we have had average peak initial production rates in excess of 4.0 million cubic feet of gas per day, with several high-rate wells still climbing while cleaning up.

 

As Steve noted previously, with our current capital program of $900 million in the Fayetteville and resulting additional well count, we project that the division will now create free cash flow of roughly $100 million this year using prices to-date and strip pricing going forward.

 

On the midstream side, our gas gathering business in the Fayetteville Shale continues to perform well and at June 30 was gathering approximately 2.3 billion cubic feet of natural gas per day from 1,886 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 flattening production profiles from our BML horizontal and Dean vertical wells over the past several months. 

 

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We have seen further encouragement in the completion of our eighth well, the Sharp vertical. The first stage we stimulated in the Sharp well is in the “lowest” part of the Brown Dense and is an interval that had not been tested in any of our previous wells. This interval seems to be more highly fractured than we’ve seen in previous sections.  This interval of the well has been testing just over a week and it is continuing to increase in rate and flowing pressures, with rates over 125 barrels of 48-degree gravity oil per day and 326 Mcf of 1,275 Btu gas per day. We will likely stimulate and test the remaining 3 intervals of the well in the next few weeks.

 

We have also seen industry activity pick up across the area, as both public and private operators have requested drilling permits and two of five planned wells have been spud with the remainder planned for later this year and or early next.

 

Overall, we remain excited about the Brown Dense and will continue on with our work to unlock the commerciality of the play.

 

In our Denver-Julesburg Basin oil play in eastern Colorado, we have begun flowback on our 15-stage Staner well on July 18th and will watch the performance of this well over the next 90 days.

 

In the Bakken, we have concluded our testing of our second well.  We are disappointed with the results we have seen and will move on to other opportunities in our New Ventures portfolio.

 

In New Brunswick, we have successfully acquired two lines of 2-D seismic data and look to acquire 2 more lines of 2-D this quarter. We remain on-track with our current goal for first drilling in late 2014.

 

To close, we are delivering more to our shareholders and believe the future at Southwestern Energy is very bright, driven not only by the producible assets we have in-hand but also because of the potential of the early-stage projects that we are working on. We will continue to update everyone on these over time, however some are undisclosed for now. In the meantime, we will remain vigilant in continuing to drive the process of innovation, keeping our costs as low as possible and adding significant value for each dollar we invest. 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 – Senior Vice President and  Chief Financial Officer 

 

Thank you, Bill, and good morning.

 

As Steve mentioned, our results in the second quarter were outstanding, driven by higher production volumes and higher gas prices. Excluding non-cash items, we reported record net income of approximately $190 million, or $0.54 per share, for the second quarter more than doubling prior year net income of $91 million, or $0.27 per share. Cash flow from operations (before changes in operating assets and liabilities) was a record $493 million. This was 16% higher than our discretionary cash flow generated in the first quarter, and up 39% compared to this time last year.

 

Operating income for our Exploration & Production segment was $253 million, over three times higher than the $82 million we recorded in the second quarter of 2012, again primarily due to higher production and higher realized gas prices, partially offset by higher expenses due to increased activity.

 

We realized an average gas price of $3.85 per Mcf during the second quarter, compared to $3.12 per Mcf in the second quarter last year, and have 169 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 have protected approximately 128 Bcf of our remaining 2013 projected natural gas production from the potential of widening basis differentials through hedging activities and sales

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arrangements at an average basis differential to NYMEX gas prices of approximately ($0.06) per Mcf. This includes approximately 50% of our expected Marcellus volumes that are protected through year-end. Although both NYMEX and field prices have declined from levels seen earlier in the year, we continue to watch the gas markets closely and will look for opportunities to add to our hedge position.  One of the softer basis points that the Northeast market has seen this summer is Dominion, which has the potential to impact approximately 15% of our Marcellus production through the shoulder season. Another thing to remember is that when the new pipeline projects go in service this fall and winter demand arrives, these differentials should improve, and this is reflected in our expectation of a $0.55 discount to NYMEX for balance of 2013.

 

Our cash operating costs of approximately $1.24 per Mcfe in the second quarter continue to be very low relative to the rest of the industry. Lease operating expenses for our E&P segment were $0.85 per Mcfe in the second quarter, up from $0.79 per Mcfe in the second quarter of 2012, primarily due to higher 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, down from $0.27 per Mcfe a year ago, and were lower due to decreased employee-related and information systems costs. Taxes other than income taxes were higher at $0.11 per Mcfe, compared to $0.08 a year ago. Our full cost pool amortization rate in our E&P segment fell to $1.05 per Mcfe, compared to $1.38 last year. 

 

Operating income from our Midstream Services segment was relatively flat with last year at approximately $73 million during the quarter.

 

At June 30, 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 excellent shape. We currently expect our debt-to-total book capitalization ratio at the end of 2013 to be approximately 34% to 36% at current strip prices.

 

With our outlook for increased natural gas production, coupled with higher gas prices than budgeted and a low cost structure, we believe we have not only a record year ahead in 2013 but also the ability to create 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.

 

 

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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 and six months ended June 30, 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.

 

 

 

 

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