西南能源 (SWN) 2014 Q1 法說會逐字稿

Greetings. Welcome to the Southwestern Energy Company first-quarter 2014 earnings conference call.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, Chief Executive Officer for Southwestern Energy Company. Please go ahead, sir.

Thank you and good morning. Thank you for all of you joining us today. With me today is Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Executive VP of Exploration and Business 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 results, you can find a copy of all of this on our website at www.SWN.com.

Also, I'd like to point out that many of the comments during this teleconference are forward-looking statements and involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more detail in the risk factors and our forward-looking statements section of our annual and quarterly filings with the Securities and Exchange Commissions. 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.

Now, let's begin. Our first-quarter results were the best in the Company's histories. Quarterly records were set for production, adjusted earnings, cash flow, and EBITDA.

Our initial productions rates in the Fayetteville Shale continue along the record trends established in 2013, and the quality of our newest wells and Marcellus has created exciting growth that will continue for several more years. Our new Sand Wash play in Colorado closed yesterday, and we continue to move our exploration concepts forward in the DJ Basin and are on pace for testing other exploration projects later in the year.

You might ask, and many of you have already written comments about our guidance. Shouldn't higher gas price or 23% growth in production or the closing of $180 million acquisition change the overall guidance for 2014? The answer is, maybe. But we are not ready to confuse you today with any guesses about the rest of the year.

Certainly, production is ahead of guidance. So there's upside to that number for the year, we want to better determine the activity we can really do in the Niobrara acquisition, fine tune the capital needs in other parts of the Company, and watch the gas price for at least one more quarter before making any new projections.

Speaking of natural gas prices, they continue to be a topic of interest for all of our investors. As we stated over the past, we believe gas will trade between $4 and $5 for the foreseeable future, with weather spikes that can break either side of that trend for intervals up to 12 months.

Within that price range, both our Fayetteville, our Marcellus economics match with almost any basin in North America. So I have confidence that SWN will continue to set more records next quarter and throughout the year.

With that, I will now turn the teleconference over to Craig for an update on our first-quarter results.

Thank you, Steve and good morning everyone. As Steve mentioned, we had an excellent quarter driven by higher production volumes and higher realized prices. Excluding certain non-cash items, we reported net income of $231 million or $0.66 per diluted share for the quarter, compared to $146 million or $0.42 per diluted share for the first quarter of 2013.

Our cash flow from operations before changes in operating assets and liabilities was approximately $617 million, a record for discretionary cash flow generated in the first quarter, and up 45% compared to this time last year. Additionally, our cash flow exceeded our capital investments in the quarter, resulting in free cash flow of $75 million.

Operating income for our E&P segment was $352 million, 2 times the $176 million reported in the first quarter 2013, and primarily due to higher production and higher realized gas prices, offset slightly by increased operating cost and expenses due to increased compression and gathering cost. Including hedges, we realized an average gas product of $4.19 per Mcf during the first quarter, which was up from $3.42 per Mcf in the first quarter of 2013.

In the Marcellus, excluding hedges, we realized an average gas price of $5.09 per Mcf in the first quarter. We currently have 349 Bcf or approximately 61% of our remaining 2014 projected natural gas production hedged through fixed-price swaps at an average price of $4.35 per Mmbtu. We also have 240 Bcf of natural gas swaps in 2015, at an average price of $4.40 per Mmbtu.

Our cost structure continues to be one of the lowest in the industry. With all-in cash operating cost of approximately $1.36 per Mcfe in the first quarter, compared to $1.18 per Mcfe the last year. That includes our LOE, G&A, net interest expense, and taxes.

Lease operating expenses for our E&P segment were within our guidance range at $0.93 per Mcfe in the first quarter, up from $0.81 per Mcfe in the first quarter 2013, primarily due to increased third-party gathering cost in the Marcellus Shale, due to higher activity levels in Susquehanna County, and higher compressor fuel cost as a result of higher natural gas prices.

Our G&A expenses were also within our guidance range at $0.25 per Mcfe, up from $0.21 per Mcfe a year ago, and were higher due to increased personnel costs associated with incentive compensation and driven by improved Company performance. This had the effect of increasing our G&A per Mcfe by $0.07 over the first quarter of 2013.

Taxes other than income taxes were $0.13 per Mcfe, up from $0.12 a year ago, and our full cost pool amortization rate in our E&P segment was $1.10 per Mcfe, compared to $1.09 last year. While our cash cost per Mcfe increased over year-ago levels, the increases were driven by improved Company performance, higher natural gas prices, and growth of our Marcellus operations.

Operating income in our midstream services segment rose 8% to $83 million in the first quarter compared to the same quarter in 2013, primarily due to increasing gathering revenues from our Fayetteville/Marcellus Shale plays. Additionally, EBITDA generated by midstream services segment in the first quarter rose 10% to $97 million compared to the same period in 2013.

At March 31, 2014, our debt-to-total-book capitalization ratio was 32%, down from 35% at the end of last year, and our liquidity continues to be in great shape with only $160 million borrowed on our revolving credit facility at March 31. We currently expect our debt-to-total-book capitalization ratio at the end of 2014 to be approximately 28% to 30% at current strip prices.

I am proud of our first-quarter results and am very excited about the future. I will now turn it over to Bill Way for an update of our operational results.

Thank you, Craig and good morning everyone. To echo Steve and Craig's comments, the first quarter of 2014 was a terrific quarter, setting records in every key performance indicator, and doing so in the face of a very harsh winter operating conditions, especially in the Fayetteville. I'm very proud of the hard work and commitment of all of our employee teams across the Company who came together and delivered our strong results.

In the Marcellus Shale, our production in the first quarter 2014 more than doubled versus prior-year levels to 58 billion cubic feet of gas, which is more than our Company produced from the area during the full year of production in 2012. Our gross operated production surpassed 800 million cubic feet of gas per day during the quarter, and is projected to increase to nearly 1 billion cubic feet of gas per day by the end of 2014.

We are continuing to see increases in well productivity from ongoing refinements and completions, well placement, and from incremental compression, especially in our Range area in Susquehanna County, where gross operated volumes have now eclipsed our volumes coming out of Bradford County and have reached nearly 400 million cubic feet of gas per day. Separately, we've spud our first three wells out of a four-well planned upper Marcellus test in Bradford County, our first production from these wells expected later this year.

On the midstream side of the business, we were gathering 436 million cubic feet of gas per day from 96 miles of gathering line in the Marcellus Shale at March 31. We are planning to add considerable amount of compression in Northeast Pennsylvania in 2014, which includes placing in-service 18 compressors, 12 of which will be located in the Range area, and by the end of the year all of our operated volumes in Bradford, Susquehanna, and Lycoming Counties will be compressed.

Our gas marketing team is constantly working towards finding additional sales and firm transportation opportunities for our gas, and their efforts in the first quarter strengthened our position in the Marcellus by adding 118 million cubic feet a day of firm transportation. We now have firm contracts in place which allow us to reach 1 billion cubic feet of gas per day of firm transportation out of the basin by year end 2014.

Through this firm transportation, we are able to assure flow everyday and reach our 10 different liquid market points. We will continue to update you as we are able to obtain more firm transportation out of the area as the year progresses.

We're very proud of our Marcellus results to date. Our production growth coupled with significant progress on derisking acreage, improving well performance, and reducing costs has created the potential for our Marcellus business to now be cash flow positive in 2014, assuming current NYMEX prices. I look forward to reporting more about this in the future.

Switching to the Fayetteville Shale, I'd first like to speak about the tornadoes in Arkansas earlier this week. A severe storm system comprising of more than 30 tornadoes passed through the southern US on Sunday night, killing at least 15 people in Arkansas and devastating hundreds of homes and neighborhoods. In Arkansas, entire neighborhoods have been reduced to rubble in the wake of one storm that left a path of distraction 30 miles long in areas where many of our employees and contractor employees live.

The hardest hit towns were Vilonia, which sustained damage from an EF4 tornado, and Mayflower, both of which are located south of our Fayetteville operations. SWN employees have been affected by the series of deadly tornadoes and several of the SWN family have experienced great loss, including homes destroyed and loved ones lost.

We're heavily involved in supporting this area with resources for the Greater Arkansas America Red Cross to aid in the relief efforts there. Our employees are also rallying to the support of their colleagues and friends that were impacted by the storm through donations of help with cleanup. Many of our contractor companies have joined with us, and our crews and equipment on the ground helping with cleanup and are providing clean water to many residents that have been affected. Our thoughts and prayers go out to our Southwestern Energy employees and contractor employees and their family, friends, and neighbors that have been affected by this disaster.

The Company fared far better as far as our drilling and production operations are concerned as a result of this. We did not suffer material interruption or damage or lose any production due to the storm.

As for the first quarter, we placed a total of 105 wells online in the Fayetteville Shale, with an average initial production rate of 4.3 million cubic feet per day, which is 29% higher than a year a go. Our first-quarter results included two wells with initial production rates over 10 million a day, and April is already off to a great start with two wells which had peak rates of 11.3 million and 10.7 million cubic feet per day respectively. In April, we also surpassed for the first time, the 2.1 Bcf a day mark for the field.

During the quarter, we also continued to test in the upper Fayetteville. One of the wells completed in the first quarter had a CLAT of 4,030 feet at an IP rate of 3.8 million cubic feet per day, producing from a 10-foot interval in the upper Fayetteville. We are currently in the process of drilling the remaining 19 upper Fayetteville tests we'd originally planned and expect these wells to be completed this summer.

We continue to work to drive our costs lower. One are the components of our vertical integration that we are currently upgrading and which will benefit future cost is the introduction of our new SWN drilling rigs, which began this week. We've contracted to build seven new rigs, the first of which began drilling its first well on Tuesday in the Fayetteville. The rigs are scheduled to be delivered every 45 days, and the last one being delivered in December.

We expect that these new AC-powered, dual-fuel rigs will trim a full day out of the drilling curve, further reducing our drilling costs. 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 are providing an average savings of approximately $415,000 per well. And I must say our vertical integration is the key component of our strong economics and ongoing improvement.

On the midstream side, our gas gathering business is gathering approximately 2.3 billion cubic feet of natural gas per day, from 1,961 miles of gathering lines on March 31.

Moving to exploration, yesterday, we closed on our previously announced acquisition of approximately 312,000 net acres in Northwest Colorado targeting the Niobrara formation. We plan to begin a five-well drilling program in June that includes four vertical test wells and one horizontal well targeting a roughly 400-foot section in the rich condensate volatile oil window of the play.

In our Denver Julesburg Basin play in Eastern Colorado, we plan to spud our third well in mid to late May, testing the Marmaton and Atoka sections. We will also test two additional exploration ideas in 2014 that we've not yet disclosed.

In closing, I'm very proud of -- our team and our first-quarter accomplishments and I'm excited about what is yet to come. Looking ahead to the remainder of 2014, more records are within sight due to the combination of increased production, higher realized prices, and our low-cost structure.

That concludes my comments. We will now turn back to the operator who will explain the procedure for asking questions.

(Operator Instructions)

Doug Leggate of Bank of America.

I wonder if I could hit two questions, please. First of all, can I hit the guidance issued? I realize the need for some conservatism. But given how strong your first-quarter volumes were, could you speak to the exit rate on any reasons why that shouldn't continue through the second quarter? I got a more specific question for follow-up, please.

The really isn't any reason that we shouldn't continue growing at a good pace. Certainly, the 23% year over year, if you look at last year, the first quarter was a low number. I don't know that we are going to be in the 20% growth rate this year. But we are on the high side of guidance, I think we'll stay on the high side of guidance as you go through.

The real issue, the reason we haven't a changed guidance, is that frankly, the Marcellus is performing much better than we thought. We may be able to significantly back down on some capital and still hit the numbers we want. We want to watch that for a quarter or more before we make that decision. You may see a lower capital at some of our areas and more production. So that's one of those good things you can have --

I want to go to the Fayetteville, Steve, if I may. Looking at the IP rate for the latest batch of wells, the IP rate obviously fell a bit, but the 60 day rate is up quite substantially. Obviously, there's issues with [lasso] wins there. But I was just wondering if you could help walk me through how that dynamic is changing, it looks like the type curve on these longer lassos is changing quite a bit compared to what we might be seeing currently. Obviously, it looks like it's got upside implications for the EUR. Can you give an idea of what's going on there between the lower upfront rate and the significantly bigger 60 day rate? I'll leave it at that. Thanks.

I will let Bill address that.

Our IP rate by quarter is determined partly by where we happen to be drilling. As we said before, geography impacts that number quite a bit. In the fourth quarter, we had a number of longer lateral opportunities in high test areas. We continued to move around of the field, as I mentioned in my opening comments. Testing these higher rate wells, modifying our completion processes and those high rate wells roll through the 30 and 60 day rate, and we are seeing that they are sustaining production at this point.

We will continue to spread across the field additional testing with both high-rate tests and the resting of wells to pull the water off, which in many parts of the field is also contributing to increased rates.

(multiple speakers) Two conference calls ago we started seeing the high-rate wells. The big question was, are they going to sustain? I don't know that we know the answer to whether it's going to sustain yet or not. But certainly some of them are. So I would guess we need another couple of quarters before we can say yes, you are getting more reserves and better wells out of them. It's sure interesting today.

Steve, is there a way that we can figure out what proportion of your drilling backlog is in that longer lateral-type design versus the more standard wells that you had previously?

There's really not -- it's really not just a longer lateral. So need to be a little bit careful there. But somewhere between 20% to 25% of this year's drillings across the southern part of the field doing these kinds of things.

Some of those lateral lengths are dictated by unit size and geography at the well site.

That's helpful. Thanks, guys, appreciate it.

Gil Yang with DISCERN.

To follow-up on Doug's question, the 20% to 25% of the wells doing these kinds of changes to the completions and to the designs, if everything works as we might best plan, will it be 20% to 25% limited by the geology? Or could it be a substantially higher proportion of the wells that you're drilling?

As I think Steve mentioned, it's probably a bit too early to tell. We are drilling in areas where we've tested less over the years and spreading out across the field, so in some respects as these high-rate wells continue to surprise in terms of performance, we have yet to go across the entire field and test this concept.

So what we've tried to say, is let's keep IPs on trend. But we are going to continue to test this. For a field that has the number of wells that we drilled in it, and we think it's very exciting news that we can continue to put out wells that exceed 10 million a day of production that can't sustain 30 and 60 day rates. Please stay tuned on that and we will keep bringing that news to you.

Let me just add that you will see our Investor Relations material here in a couple of days. I got a glance at it last night. For those who have seen it in the past, we've got where we drilled in the last 12 months and we've got stars on the map where it's greater than 5 million a day. Going back to Bill's comments, you are going to see a lot of stars on what people thought were the edges of the field. So there is some different geology.

And then just to remind everyone, there's the well resting that Bill talked about. That doesn't necessarily match with the geology and there are surface things we've done to debottleneck, and that doesn't necessarily match with either the resting or the geology. So it's a combination of all those things, and just stay tuned.

The big thing is is that the Fayetteville Shale is continuing to get better. And for 2014, I could comfortably say the kind of performance we had in the last couple of quarters, the last year, will continue through 2014. We will just see what happens as we go in the future.

Great. My second question is related to all this, given the changes to the completion designs and the improvements you've seen or you think you are seeing or hope to see, combined with the view that gas is going to be between $4 and $5, have you had a chance yet to change the criteria, so to speak, that you are using to select locations in the inventory? Are we seeing that already? Or is that sort of yet to come?

The criteria we use to select wells are several. Certainly, we want to test areas that are less tested, continue to progress the science and learnings around this integrated approach to these high-rate areas and along with the resting of wells, et cetera.

We are always looking to drill the best wells that we have and optimize the cost associated with doing that. Moving about the field to fully understand the acreage that we have. All the while, retaining the rigor of our investment criteria. Every well we have at this point has economics that are in excess of those of the investment criteria that we set out, the PBI that we talk about.

So I think that I don't see any major change to that criteria. As we learn more in a particular area, as we move through the field and there's opportunities to increase density at pad drilling, to lower cost, things like that, we are obviously looking at that. I wouldn't say there's any kind of wholesale change at this point.

If you're thinking back to 2012, 2012 with the low gas price, we were not really doing -- we're doing a modified pad drilling, we're drilling the best wells on the pad. We went back to full pad drilling, really, probably in the third quarter 2013. So we are not necessarily high-grading wells, we're certainly testing areas, we're not high-grading wells, we're drilling pads out.

The flexibility our team chose to be able to maneuver and adapt to learning is a big piece of this.

Thank you.

Dan McSpirit with BMO Capital Markets.

I was wondering if you could speak to the well resting technique in the Fayetteville Shale. Will that result in increased EURs and not just higher initial production rates? Can it and maybe should it be applied to different parts of the basin?

We are testing resting of wells across the basin. So that process and project is ongoing.

We get two benefits from resting of wells. The first benefit is the water that normally flows back with these wells when they are brought on immediately is retained in the reservoir. So the lifting cost associated with these wells goes down. The management of the water at the surface is not an issue because it doesn't come back.

In certain parts of the field, we get increased production associated with that, and the testing that we are doing is to determine is it the good news of lower cost because of savings of water in parts of the field, or, the good news of lower cost of savings water and increased production in additional parts of the field. So the testing is fairly broad and we'll continue to do that.

In terms of increased EUR, we began this testing program early last year and we've got some additional runtime to go to determine whether there's additional EUR associated with that. Certainly, we're able to get additional volume where it happens out, thus value out, and we'll just need to continue to test that to be certain.

Okay, great. And then a follow-up. If you could speak to the Marcellus well quality. We observed that the 30 day rate, at least per 1,000 feet of lateral drilled increased meaningfully in the period. What best explains that increase in productivity and should we see that trend continue?

Certainly, we've had quite a bit of increased and improved quality in the Marcellus wells. There's a number of factors to that. We are understanding better now where to land these wells, staying in zone more on these wells. We've modified our completion using a much larger sand volume in the wells than we had previously, so we've gone from 350,000 pounds of sand per stage to 500,000 pounds, getting better sand placement. So some of the lateral lengths are extending.

The real key is, the area that we're doing a lot of the drilling in at Range in Susquehanna County, the rock fabric really responds to these improved completion techniques and quality of completions, and thus the well performance is continuing to increase. As we learn more about that, we certainly expect to see that continue on trend.

Thanks again.

Another way to say that is the Bradford County wells are still good, the Susquehanna County wells are looking as good or better.

Got it. Thank you.

David Heikkinen with Heikkinen Energy.

I just wanted to quantify one thing. In the first quarter, how much of an impact did you have in the Fayetteville due to harsh winter conditions? Do you have any numbers you can put to that?

All in, in the three major ice storms that we had, it set us back about 1.7 Bcf. The team were able to claw that back to the point where we got -- we met the targets that we set out.

So the big issue was ice. We have winter weather everywhere in operation, but Arkansas was particularly hit with ice. The ability to move around. At any one time, I think we had -- in one instance I think we had 800 Bcf off the table that came back after a few days.

Okay. Then --

Bill hesitates before he answer the question. One of the things I keep telling the guys around here, our job is to get results, not have excuses. So I had to nod to him to tell him he could talk about the weather. (laughter)

Thanks, Steve. In the Marcellus, you talked about trying to reduce gathering expenses as you go forward since you have a lot of growth coming. Could you talk about how much of the gathering expense reduction is just due to volume growth and how much was actually renegotiating contracts or installing on equipment, and quantify the cents per Mcf impact on LOE?

I guess what I would say, of this regard, because we are in active discussions, we are working with one of our third-party gatherers at restructuring our agreement to add additional volume and area to that and try to work out how we can get gathering rates down.

Certainly, as our volumes come up dramatically, we have on a unit basis been able to bring those costs down. Our aim is to keep the gathering assets that we have rightsized and full and those conversations with our third-party gatherer are well in progress, and we should be bringing you some further information about that shortly.

Okay. That was my two questions. Thanks.

Scott Hanold with RBC Capital Markets.

When you look at the forward gas prices, it seems like somewhere around $4.50-plus might be at least kind of a reasonable range to think about. Specific to say, Fayetteville Shale. What is your current thoughts on potential inventory counts at a $4.50-plus NYMEX type price? And if you could add onto that, where could it go with some of these drilling improvements and cost savings that you are seeing?

I think there's not much there between $4 and $4.50 when you talk about the lower Fayetteville. We've got somewhere just over 5,000 gross locations left to drill, when you are about $4 in that area. I don't know that well count changes much as price goes up, or some of the things we're doing, the quality of the well, I think changes. You get out of the ground faster, you get up more reserves as you go through it.

We do have the upper Fayetteville. You mentioned that. We don't normally talk about that in our numbers. But I think on the low side, you're talking 700 wells there. It could be up over 1,000 wells before it's all done in the upper Fayetteville.

And then I remind everyone that we still have the exploration acreage, 170,000 of exploration acreage in the Federal part of our acreage that we've drilled 11 wells on and we know at least a third of that looks good. But it's going to be several years before we can get to it, so that's not in our well count either.

Okay, that's good color. Maybe this is sort of a bigger picture view. When you look at the Fayetteville, then, what you described is probably at least a 10-year inventory of drilling opportunities there. When you look forward to LNG being more important coming out of the US starting in a year or two, have you all stepped back and looked at the position of the Fayetteville being able to access that area where you feel comfortable to maybe negotiate some of your volumes to that type of project?

We're talking to a lot of people. I don't know that we've got anything eminent on it. But certainly, power plants, big manufacturing, industrials are building new plants and LNG export all have need for natural gas.

The interesting thing about it is when you start talking about gas reversing out of the Marcellus and moving south, it goes right by the Fayetteville Shale. Fayetteville Shale is probably one of the best positioned gas properties in the country for the new demand. So we do talk to people, but I think we've got a premium asset there and if the right thing came along, we would make a longer-term deal. If not, we are excited about the Fayetteville and where we're sitting.

Appreciate that. Thanks, guys.

Charles Meade with Johnson Rice.

Bill, I think you did reference in your prepared remarks about the Marcellus, that you've done some derisking there. I'm wondering if you could add some specifics to that. I guess what I am really after, is maybe a review of your testing program in that Wyoming acreage and where you guys stand with that. If your plans have changed at all there.

We've derisked about 44,000 acres of our acreage and done that across the piece. Certainly there's been a lot of focus on Susquehanna County to understand the Range area better and then moving out from there.

The Wyoming County acreage, we've begun testing on. We've had a couple of different well results as we expect we would have with that line of demarcation that runs right through the middle of that acreage. Our plans are to test six wells total in the Wyoming County area along with Sullivan this year, and then continue to do some further testing in Tioga and Lycoming. I think the initial well was pretty strong in that we've had a couple of wells that have given us a little bit of question. But they are still cleaning up and we've got further work to do on that. No bad news, or good news. It's pretty early time.

Bill, we're all talking about vertical wells, right?

At this point, right.

Thank you. That's helpful. Then Steve, I was wondering, on your last call, you offered that you're realizations of the Marcellus have been good for the first two months of the year. I'm wondering if you could offer any comments on what your realizations look like in April and what timeframe we should really be paying attention to the spot prices up there?

I think right now is when you start paying attention to the spot prices. The first quarter was good. First quarter, we're plus [15], I think it was in the Marcellus. But so far in April, it's a minus number. I think you're going to see a minus number as you go through for the rest of the year.

That goes back to my initial comments about guidance. We want to see a gas price so we can start seeing if our guidance makes sense. If you remember, our guidance was $0.55 to $0.60 negative for the Company, versus historically it was a $0.45 to $0.50-type number.

We are still watching. I don't have any magic news or anything that I can tell you that says that $0.55 to $0.60 even shouldn't be a good number. Certainly, first quarter was better than we thought. But there's a lot still to go and there's a lot of different ways it can go.

Thank you, Steve. That's it.

Joe Allman with JPMorgan.

Could you talk about your ability to grow your Marcellus production in the context of your firm transportation and firm sales agreements? And talk about your need to sell on a spot basis? And if you can give us some volumes, that would be great.

Between now and the end of the year, as I said in my prepared remarks, by the end of the year, we will have just over 1 billion a day of firm transportation to our 10 liquid markets out of the area. And our growth plans are to grow in that direction. That strategy has always been to secure firm and then grow from there.

As we've talked on previous calls, taking that number further, going from 1 to 1.2 Bcf a day, one of the things that's happening in the near-term is a lot of other people have caught up with the idea of needing firm transportation. And so the cost of that has gone up significantly. In our minds, continuing to add to firm at those high numbers just doesn't make sense at this moment. So we continue to evaluate them one by one.

There are a lot of proposed pipeline projects and opportunities to bring additional firm capacity up in the area and we are analyzing those and watching those and we'll add to those as we go. We added 118 million a day of capacity by the end of the year. And we will continue to do that as we can.

In terms of spot sales, we constantly are out looking for opportunities to both sell gas on the spot market where we can make a good margin, either through our transportation or otherwise. We also have done, certainly in this first quarter gone out and bought gas and moved it to our firm transportation, realizing some fairly hefty margins as well.

We are keeping ourselves nimble up there, putting our ability to move the gas every day and then watching the market.

I would say that on any given day, you may have between 30 million and 50 million a day going to the spot market. Anything you complete during the month is definitely going to the spot market.

On a long-term basis, we don't want to get more than about 10% at the high end of that of wherever our production is and probably in the 5% range. You buy firm, you want to make sure that you use the firm, so can always make a little bit above it. But we will just follow the firm curve.

On that, I think on March 31, your gross production was 823 million a day. I think that was 200 million-plus a day above your firm transportation firm sales. Can you explain how you are moving that?

I'm not sure it's quite 200 million a day. I don't know if you've got the most updated graph. But it's probably a little over 100 million a day. We're doing like anyone else is, we are selling it where we can sell it.

Okay. So there are some periods where you are selling more than that 30 million to 50 million a day on a spot basis?

I'll just tell everyone. What we have got was 118 million a day. We have got an updated curve. It's smoother than the last one you saw that had a little cliff on it right now. So Brad would be happy to send that to anyone who wants it, just shoot him an email.

But if we put a pad on it, and the pad is 100 million or 50 million a day, or 70 million a day for whatever period of time til we get to the next month and we can get it to the monthly sales, it's spot sales.

At June we go up to 850 million. The period of time where we have that extra production is pretty short as well. And then go from 850 million to 1 billion right through the year.

Great, that's very helpful. Thank you.

Brian Singer of Goldman Sachs.

Wanted to pick up on your comment regarding potentially higher production and lower CapEx. You talked about improved completion techniques in the Marcellus as in part you've been using more sand is one reason for the improved well performance. Would that not though have an increase in well cost? And what would be the offsetting factor to be able to reduce CapEx?

The real short answer is, we may drill between 5 and 10 fewer wells and still hit the guidance that we had. So you are right. If you had -- sand is relatively inexpensive. So is fluid that you're pumping, but if you put more sand in, it is a little bit more expensive. It's probably a well count thing more than it's going to be. And that really just goes back to the rocks looking better in Susquehanna than we originally thought it was.

Great. And my follow up is along those lines within Susquehanna. Can you characterize the regional variability of results on the acreage pushing north, particularly those that were acquired last year relative to the southern blocks?

Again, the simplest answer is is the big block we have in Northeast Susquehanna up around New York border were about two-thirds of the way across that acreage. And it's looking very strong. It's looking very comparable to Bradford County, we haven't drilled all the way across the acreage yet. So that's still to be learned if it stays that strong to that area.

We're seeing some very good rock in that northern acreage block. It hasn't degraded like we thought it might do with geology or get in a little bit of shelf. And it still might as we go farther north, we just don't know yet.

Got it. But that's the area for the upside surprises (multiple speakers).

The Wyoming as we talked about before, Sullivan we're just in first passes of drilling wells. So it's I would guess a couple more quarters before we can make even an assessment of what we have.

Great. Thank you.

Bob Brackett with AllianceBernstein.

Quick question on reserves. Back in 2012 you took a fairly large negative revision on Fayetteville gas just on trailing price. Does that stuff reverse this year if gas price holds up?

If you think about 2013 bookings; in 2012, to put it in perspective, we had about 1,500 puds on our books. At the end of 2013 we had about 1,200 puds on our books. We had part way back in 2013, and then as long as price stays above $4, the average price of 2012 was $4.12. We should get most of that back on our books. Yes, you will have continued reserves coming back on our books from just adding price to the overall situation.

Got you. The other, a little off topic, I hear you guys using the term SWN more often. Is that what we should call you? And are you guys rebranding, now that northeastern becomes more and more important?

I don't know we are rebranding so much. We're SWN, internally all the time. That's maybe the case. I can tell you that we did try to copyright SWN, and it's already copyrighted. So I don't know that we will rebrand to SWN.

Okay, I will stick to the long one.

Take the long one. (laughter)

Tim Rezvan with Sterne Agee.

I was hoping to circle back on the theme of spending. It looks like you're going to have a pretty good free cash flow surplus this year. And you just teased the idea of maybe cutting spending a bit to hit guidance. This leaves you under levered relative to historical levels. With Fayetteville economics improving and gas prices rallying, how do you think about your rig count or activity levels in the back half of the year?

That's why we haven't changed our guidance, yet. Because certainly one of the options would be if we feel comfortable about the price not just for this year, but for the next three or four years, we might go faster in the Fayetteville, and we just have to make that decision. And so that's part of the options we have.

Certainly, as we test some of these exploration ideas and any of those work, those could be places to put capital, not necessarily this year, but in nearby future years. And in the Niobrara, if we can get all of the permits that we want and get all five wells drilled, there's about $50 million of capital there on top of our acquisition. We just don't know yet whether we can actually do it or not. So that's part of the variables and we are not updating guidance quite yet.

Do think you might have an answer by the 2Q call?

I think we probably will. Certainly, our Board would like us to have an answer by then.

Okay. And then last one on acquisitions. Unlike some other E&Ps that have really paid out a premium for known derisked inventory, you favored more exploratory acquisitions. Given the head fakes we've seen out of Brown Dense, just the uneven results, how do you think about buying exploratory rock versus getting something that you know you can develop going forward?

It's a matter of what risk you take. Certainly, if you get in early and are first mover and do the exploratory part, it's less expensive to get into it. But you have that risk that it may not work, and as you said the head fakes of Brown Dense. We know internally that we are going to have more of those head fakes than we have successes. But historically, we found Fayetteville, we found the Marcellus. When you find those, those cover up those other ones as you go through.

When you start going to second mover or you go finally do an acquisition, you certainly have to pay a lot more for it. You've taken some risk out of it, but you've also taken some of the potential upside. And for us, you've taken out some of our skill set. When I some of our skill set, we are good at drilling wells and developing the very large projects. If it's already halfway developed, we could've took the risk out of it and that took some of that learning things that we could've done and potentially done better.

We like getting in early. Not necessarily, it doesn't have to be just right at exploration, but we like getting in early and then applying that vertical integration, applying the logistics that we do, and all the other things that we are good at, to add a little bit extra that someone else can't do.

Thank you for the color.

Arun Jayaram with Credit Suisse.

Steve, I also wanted to follow-up on that free cash flow question. For some time, you guys have been outspending cash flows as you are at an early stage of spending in the Marcellus. You've had some of the Brown Dense spending. And then obviously low gas prices.

Now that you are essentially moving into a free cash flow mode, I was just wondering what the long-term outlook's going to look like for SWN. Are you going to try to grow within cash flows? Or are you going to, perhaps, outspend a little bit to drive the NAV forward? Just trying to get some thoughts around that.

You can't go forever and outspend your cash flow. Something doesn't work there as you go through it. But our goal is to have more projects than we have capital and then have to worry about how you make those projects work. So we're still on that goal, and we will still do the exploration and all those various things that go with it.

Obviously, if we don't get that or the timing is not right and then you have some excess cash flow, then you have to figure out what you are going to do. As I mentioned before, the Fayetteville Shale has a lot of locations that go with it, and as long as price looks reasonable going forward, we probably can go faster there. We just have to be certain that we don't think this price today is a head fake.

Steve, if you're going to add incremental capital into your business, it sounds like it would go in the Fayetteville ahead of the Marcellus. Is that fair?

It would today. It may not a couple of years. But going back to the fact we want to follow that firm curve, we've put all the capital we can to it right now to follow that firm curve. There isn't much more we can do there.

My follow-up is on the cost of firm today. Bill mentioned it's getting a little bit more competitive. Can you comment on where the market is today and your willingness to sign firm at call it today's market prices?

The willingness to sign firm depends on where it's going and how many sales points it has. If it's only a single sales point, and it's not a really good sales point, then no one's going to pay a lot for that. To put it in perspective, our average all-in price up there is just something over $0.30 for the transportation that we have to date. And looking at similar projects that are out there, there are several projects that are $0.70 [an M]-type projects and there's some as high as $1 an M.

In some cases, that may make sense because they are going to very high-quality markets, in other cases it doesn't make sense. So that goes back to Bill's comment. It's almost double going to some markets, and we just have to determine if that make sense or not for us as a Company.

Alright, thanks a lot.

Michael Rowe with Tudor, Pickering, Holt.

I was just wondering if you could just provide an update on where you expect your firm transportation to be in the Marcellus, I guess with the cadence throughout 2015 with these recent additions?

I don't have the exact number in front of me. But I think it's a little less than 1.1 Bcf a day at the end of 2015 right now.

Okay. Great. I was just wondering if there was anyway you could provide any additional color on which markets you are delivering gas to by hub in the Northeast.

A lot of companies have done that. I hesitate. The reason I hesitate, is the assumption is that that gas can only go to that point and there's no way to move things around. I remind people, that both in the fourth quarter and first quarter, we had capacity on one line, Leidy was selling for less than $1. We could take the Leidy gas, move it to another sales point, and make $3 an M on it.

And so in general, I think we could tell you that we are trying to do the points of a compass, you're going several different directions and even that out over the next two to three years. But anyone who's trying to go to a certain point and say this point is going to be bad for a long period of time, this point is going to be good, is going to be surprised as the year rolls around.

Thank you.

Stephen [Zephergans] with Simmons.

All of my Fayetteville and Marcellus questions has been answered. Is there any intention to add anymore frac spreads this year to the two that you currently have?

At this point, no. We made a decision on that. What we do, is we look at our utilization. We look at projects that we have and we look at the activity level by play to make sure that if we were to add any kind of additional equipment we'd get 100% utilization out of it.

For example, we're looking as a part of the whole Niobrara evaluation, how hard we take vertical integration into that play should that play be successful. So there's lots of the valuation going on. Same in the Marcellus.

The other thing that we're able to do because we can move fairly quickly to deploy those type of spreads or equipment, that certainly impacts the price we pay with third parties. We've been able to bring down the cost of fracking, drilling, everything, because of the presence of our vertical integration businesses. Stay tuned.

Right now, we like the mix that we have in the Fayetteville with third party and ourselves. But that team is continuously looking at ways to drive costs down, and one way is to invest in not only frac spreads but others. But they certainly has to fall in the overall capital portfolio discussions as well.

To put for instance a frac spread to work, it's working 24 hours a day in the Fayetteville, and wouldn't quite be the same at all the plays, it will be a rough number, they can do about 100 wells a year. So it really just goes back when you're ready to commit to another 100 well chunk for several years, then you start talking about having a frac spread. We are not quite there, yet.

Okay, that's great, thanks. One more for me. Can you provide any more detail about the New Venture's testing programs for later this year, you talked about the five-well program with the horizontal and four verticals that you have. Where specifically on your acres are these wells going to be drilled? Have you figured that out yet? Is there any intriguing offset operator activity that's driving those decisions to drill in any certain areas? Just trying to get some thoughts on that, if there's anything additional to add there.

You are talking about the Niobrara?

Yes.

I think there is only one offset operator that's doing anything. It's a private company out of Denver called Axia. I don't know what exactly their program is, but they are deeper in the basin for the most part, a dry gas, was a little bit of liquids in northern wells.

We are going for a liquids window that will have some gas with it. So the intriguing part and the thing we are watching for, is these wells are set up to go both laterally and across that window, and fine tune where that window might be and what the productivity of that window is. There aren't any really other operators right there doing anything, but each well will tell us a little bit about how big it might be and the quality of it.

Thank you.

Jeffrey Campbell with Tuohy Brothers.

Just to jump back out on the Niobrara that you were just talking about. You said there's not a lot of offset operators there. But did you get a reasonable amount of well control from the acreage that you acquired, and was there some prior drilling there that was helpful?

There were several wells drilled. Some go all the way back to the 1920s and 1930s, where there was actually some conventional production on the Niobrara out of structural traps. And when I say conventional, it was actually fractured in Niobrara, but it produced our structural traps. There were wells drilled by Quicksilver and Shell over the last two to three years that while weren't in the locations that we would want to drill and weren't even really tested the way we'd want to test, gave us a lot of geologic information.

I like to say the key well that made us excited about the play were these wells drilled in that gas window. You would say why would the gas window make you excited? We had mapped up the area, projected it was going to be gas. It kind of confirmed our thought process in the play, and that's what got us to the point where we wanted to pick up the acreage and go from there. In the general area, there's probably almost 100 different wells drilled. But most of those are on those conventional structures from the past.

Okay. Great. Thank you. That's helpful. I missed the first part of the prepared remarks. I apologize if I'm asking for something that's already been disclosed. But could you give an update on the DJ basin, please?

Yes. We will be drilling an additional well in the western portion of our acreage here in the next period of time. A vertical test for Marmaton and Atoka to again look at oil cut and test our process. We've got some wells to follow on behind that, depending on the outcome of this next test.

As to remind everyone, we drilled two wells. The best we had was about 140 barrels a day of oil rate. But we had water, and we are actually going deeper into the basin and hoping that we get rid of that water. If you get rid of the water, then we could have a commercial play. It will take one, maybe two more wells to figure out if it's going to work there.

Thanks very much. I appreciate that.

Subash Chandra with Jefferies.

The first question is one of context and to revisit the free cash flow theme. It seems like I see a parallel here in the Barnett as in the Fayetteville, where you did see leading-edge wells improve and become more efficient. But in the Barnett production never went up. But you can keep production flat with 10% of the rigs.

So when I see these developments in the Fayetteville, I know you've talked to maybe accelerating activity and the hurdles in doing that. But is there a view that you might see this thing as really a cash cow over time? Where the hurdles are so high, $5, $6 gas for acceleration, or is that too extreme of you for the Fayetteville?

I don't know about extreme view or not. Fayetteville Shale for the last couple of years, we've been working on keeping it within cash flow. And in 2013, I think it generated about $75 million of capital over its capital budget. To run a rig, you need over $100 million for a year. So really, there was no decision or discussion until very recently that you'd have enough money to even add a rig, and a rig would add about 60 wells a year to the program.

We've intentionally lived within cash flow and we've done it for two reasons. One, you got to get to a point where you do that on each of your projects and generate excess cash so you can fund exploration and other things you are doing.

The second thing was as gas price moved up and down, that was our way to moderate; if the gas price went down we went a little slower, if it went up, we went a little faster. So we will stay within cash flow in the Fayetteville Shale. It doesn't necessarily mean we will take all the cash flow of the Fayetteville Shale. We will look at that and make more decisions as we go in the future.

As far as growing the Fayetteville Shale, we are not growing it. It's as you said, it's like the Barnett. We've got a total in the play, it's really us drilling with eight wells capable of horizontal production. If you double that rig count, that production will go up. It's really just a matter of capital and rig count that drives whether we have flat production or increasing production.

Okay. A follow-up. You referenced the Quicksilver and Shell wells. It wasn't clear from talking to Quicksilver. But were those wells in the fractured Niobrara? Did you hint that maybe they were unstimulated, under-stimulated? What were the shortfalls of their locations and completion designs?

Both of those companies took slightly different approach to each other. Certainly, an insanely different approach to what we were doing. They were working around these fields that were there. They were under the thought process that if you put water on the formation it would damage the formation. So except for I think it was two fracs in a Quicksilver well, all the wells that Shell and Quicksilver drilled either were not fracked or were fracked with butane or something else where they put no water on the formation and didn't give really good fracs away.

Actually, there's company down dip with slick water fracs and have shown that the formation is not susceptible to damage. So we are looking at it as a more conventional, unconventional, where they thought there was some rock characteristic issues. And we're looking for natural fractures around these fields. So it's a completely different concept.

Okay, if I could just add something real quick. Was that the clay content they feared?

Yes. There's actually a paper written back in early 1970s that had said the Niobrara had clay in this area and you had to be careful about it. We have not seen any in the core. And as again, certainly the recent fracking verifies that. We haven't seen that characteristic, so we don't know exactly why that paper was written the way it was or what the characteristics were that made that paper happen that way. But that was the thought process.

Understood. Thank you very much.

Joe Magner with Macquarie Group.

One quick question. Some of the concepts in new well designs and completion techniques that you all are testing, are those enough in and of themselves to perhaps go back to the drawing board and reevaluate plays that either some were thought not to work or be commercially viable? Or new plays that again might fall into that bucket, but with this new line of thinking and reasoning perhaps might work?

Just curious if that is enough to maybe bring some of these plays over the hurdle, or reservoir qualities still going to be the key differentiating factor, and these are just going to be used to enhance results? Curious what your thoughts are there.

I'd expand the category, not just the way you complete the wells, but the way you drill the wells. We can do things considerably faster, cheaper today, and there's certain thought processes on how you complete wells that's different than it was even 18 months or two years ago. So yes, I think you can go back and start reevaluating plays that may not have worked or plays that worked, but you might go get extended out a little farther as you go through.

I haven't seen anything that we've done that's radically different that says here's a new play and you've got to go into it. But we are doing some fairly radical experiments in some of our fracs. So I don't know that that won't happen.

Great. That's all I got. Thank you.

Sameer Uplenchwar with Global Hunter.

Quick question on trying to understand Brown Dense. Did you mentioned earlier that you have a decision by 2Q? Or is the timing a little late on that and what are you expecting over there?

And then the second question on New Ventures. You mentioned at the beginning of the call that you are looking at other plays. Are they natural gas plays, liquids plays, and also are they in the lower 48 or internationally? Thanks a lot.

Let me start with the New Ventures. New Ventures, we will roll out a couple of new plays during the year. If and when we do that, we'll talk about them at that point in time. Any point in time we are working on eight or nine ideas, some of those ideas are gas and some of them are liquids.

Internally, we don't separate out gas and liquids, we just look at economics. I tell people all the time, if we can find another Marcellus, I would love to find another Marcellus. We don't do anything from that perspective.

From international versus US, everything we are doing right now is in North America. A reminder we've got New Brunswick, as well. But that doesn't mean someday we won't be international, just right now all the ones we're working on are North America.

Going back to the Brown Dense and when we will know something, I saw some things written today about well this latest well has a low rate. That's not even the issue. The issue of the latest well, is it's a mile away from our well that's very economic. And it has a black oil in it, and the well that we're very economic has a honey-colored light liquids as you go through.

When you do all the fancy work on it and try to figure out what the sources are, they came from the exact same source. The black looks like it's water washed, for those who are into those kinds of things. The other doesn't look like it's water washed.

So there's a very complex history in the Brown Dense. I kind of put it in the category of the bully. Sometimes I tell you when the bully comes up, the thing to do is go fight him. But you don't want to do that too many times, you get beat up too many times if he keeps beating you up. Right now, Brown Dense is beating us up. So I don't know how long we're going to take the beating. Maybe it's a quarter, maybe it's two quarters, not too far out.

And yet, we've got a good well. There's another well that the industry has drilled that's a good well. There's some other wells the industry is drilling in the area. We've got some more ideas. I don't want to go into those ideas because they could have consequences for other plays. But we will continue to work on it. But we are not going to talk much about it.

If you notice, Bill didn't say anything about it. We had one paragraph and you will see in our Investor Relations it's going to go in the back of the Investor Relations when we see it from here on. We'll just keep working on it. If we find something good, we will tell you. If not, that's it from the Brown Dense standpoint.

Thank you.

Final question from Joe Allman with JPMorgan.

Could you talk about how constrained your production growth is in 2015 and beyond, given the firm transportation and firm sales agreements you have in place right now? I haven't seen the latest spreadsheet. Also, talk about your expectation for adding additional firm transportation and firm sales in 2015 and beyond.

We haven't guided or even talked much about 2015. I don't know whether it's constrained or we're going to grow rapidly or we are not going to grow rapidly. Stay tuned on that part.

As far as firm capacity, and what we can add in 2015, there's not much out there, frankly. So I wouldn't expect much more than we have now. We keep chipping away, and whether we're going to add that 118 million this time. But we will keep chipping away at it, but there's not a big amounts there that come available in 2015.

The new capacity that we were talking about is something beyond 2015. And really frankly, beyond 2016 into 2017 as we go through from the Marcellus. But don't just assume the Marcellus may flatten a little bit. On the firm, don't assume that that means the Company is going to flatten. There's a lot of different options we have. Again, stay tuned for 2015. We are still trying to figure out guidance for 2014.

As of right now, by year end you expect to be over Bcf per day gross -- is there a possibility that 2015 is flat from there? Or no?

Just stay tuned. I don't know enough, yet.

Got you. Could you describe the other options you have aside from the additional FT and firm sales?

Well the biggest option you have is slowdown your capital and just follow firm curve, and have your growth rate, if you're going to have growth rate from somewhere else. We are going to do what's economic. And we're going to do what makes sense. The growth rate will be the growth rate.

Okay, great. Very helpful. Thank you.

At this time, I'll turn the floor back to Management for closing comments.

Thank you. The average gas price through May averaged $4.84 this year. You only need $3.40 average price for the rest of this year to achieve $4 for 2014. If I think back a year ago, that would have been an almost impossible discussion to even think about today.

It was also seemed highly unlikely that Southwestern Energy would generate $75 million of free cash flow above our investments in the first quarter of 2014. And it was even more improbable that we would hint that capital efficiency is so strong that we may be able to incorporate a large part of our $180 million acquisition in our current capital budget and still beat original production guidance.

As we've demonstrated this quarter and really over the last few years, we are designed to provide good returns in low-price environments and great returns when it's $4 gas. We continue to believe that true success starts with curiosity. Curiosity leads to learning. Learning leads to new ideas, to new projects, and new ways of doing things.

I think as you've seen in today's conversation and our press release, all of those things are happening with what we are doing. And through success, going back to the last question, isn't talking about or targeting growth rates, it's based on firm economics. I think we've shown a disciplined approach to delivering those above-average economics. When we give you above-average economics, we provide high growth.

My promise to you is that we will continue to keep focused on what is true success. That's building our future by improving the return on every dollar we invest. 2014 is going to be fun for us and for you. So stay tuned. Thank you for listing. Have a great weekend. And that concludes our call.

Thank you. You may now disconnect your lines at this time. Thank you for your participation.