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Southwestern Energy Company (NYSE:SWN)

Q1 2014 Results Earnings Conference Call

May 02, 2014 10:00 AM ET

Executives

Steve Mueller - Chief Executive Officer

Bill Way - Chief Operating Officer

Craig Owen - Chief Financial Officer

Analysts

Doug Leggate - Bank of America

Gil Yang - DISCERN

Dan McSpirit - BMO Capital Markets

David Heikkinen - Heikkinen Energy

Scott Hanold - RBC Capital Markets

Charles Meade - Johnson Rice

Joe Allman - JP Morgan

Brian Singer - Goldman Sachs

Bob Brackett - Bernstein

Tim Rezvan - Sterne Agee

Arun Jayaram - Credit Suisse

Michael Rowe - Tudor, Pickering, Holt

Stephen Shepherd - Simmons

Jeffrey Campbell - Tuohy Brothers

Subhash Chandra - Jefferies

Joe Magner - Macquarie Group

Sameer Uplenchwar - Global Hunter

Operator

Greetings. Welcome to the Southwestern Energy Company First Quarter 2014 Earnings Conference Call. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host Steve Mueller, Chief Executive Officer of Southwestern Energy Company. Please go ahead, sir.

Steve Mueller

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’ve 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 in the forward-looking statements section 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.

Now let’s begin.

Our first quarter results were the best in the company’s history. Quarterly records were set for production, adjusted earnings, cash flow and EBITDA. Our initial production rates in the Fayetteville Shale continue on the record trends established in 2013 and the quality of our newest wells in 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 tease you today with any guesses about the rest of the year. Certainly production is ahead of guidance, so as upside to that number for the year, but we want to better determine what activity we can really do in the Niobrara acquisition, fine tune the capital needs and other parts of the company and also gas price for at least one more quarter before making any new projections.

Speaking of natural gas prices, they continue to be at top of the 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 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 conference over to Craig for an update on our first quarter results.

Craig Owen

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 ‘13.

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, two 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 costs and expenses due to increased compression and gathering costs.

Including hedges we realized an average gas price of $4.19 per Mcf during the first quarter, which was from $3.42 per Mcf in the first quarter of 2013. In the Marcellus, excluding hedges we realized an average gas just price of $5.09 per Mcf in the first quarter.

We currently have 349 Bcf or approximate 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 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 of 2013, primarily due to increased third party gathering costs in the Marcellus sale due to higher activity 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 decreased personnel cost 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 a 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 the increase in gathering revenues from Fayetteville Marcellus Shale plays. Additionally EBITDA generated by our 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 a $160 million borrowed on our revolving credit facility at March 31st. We currently expect our debt-to-total book capitalization ratio at the end of 2014 to be approximately 28% to 30% at current surprises.

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

Bill Way

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 phase of a very harsh winter operating conditions especially in the Fayetteville. I am 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 of 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’re 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 spud our first three wells at four well planned Upper Marcellus cast in Bradford County with first production from these wells expected later this year.

On the mid stream 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 31st. We are planning to add considerable amount of compression in northeast Pennsylvania in 2014 which includes placing and 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 a 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 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 of the area as the year progresses. We are 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 a 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 Southern U.S. 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 path of destruction 30 miles long in areas where many of our employees and contractors employees live.

The hardest hit towns were Vilonia, which sustained damage from an EF-4 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 in 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 American Red Cross to aid in their relief efforts there. Our employees are also rallying to the support of their colleagues and friends that were impacted by the storm through donations and 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 105 wells on line 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 ago.

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 see lateral 4,030 feet and an IP rate of 3.8 million cubic feet per day, producing from a 10 foot interval and the upper Fayetteville.

We are currently in the process of drilling the remaining 19 upper Fayetteville tests with originally planned and expect these wells to be completed this summer. We continue to work to drive our costs lower. One of the components of our vertical integration that we are currently upgrading and which will benefit future costs is the introduction of our new SWN drilling rigs which began this week.

We 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 few rigs will trim a full day out of the drilling curve, further reducing our drilling costs.

Our vertical integration at Fayetteville, which includes drillings 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 31st.

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 2 additional exploration ideas in 2014 that we have not yet disclosed.

In closing, I am very proud of our team and our first quarter accomplishments. And I am 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.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Our first question comes from the line of Doug Leggate of Bank of America. Please proceed with your question.

Doug Leggate - Bank of America

I wonder if I could hit two questions please. First of all, can I have the guidance this year? I realize the needs for some conservatism but given how strong your first quarter volumes were, can you speak to the exit rate on any reasons why that one shouldn’t continue to the second quarter? And I’ve got a more specific question to follow-up please.

Steve Mueller

There really isn’t any reason that we shouldn’t continue growing at a good pace. Now certainly the 23% year-over-year if you look at last year, it was -- first quarter was a low number, so I don’t know that we’re going to be in the 20% gross rate this year. But we’re on the high side of guidance and I guess stay on the high side of guidance as we go through. The real issue, the reason we haven’t changed guidance is that frankly the Marcellus is performing much better than we thought. And we may be able to significantly back down on some capital and still hit the numbers we want and we want to watch that for a quarter or more before we make that decision. But you may see a lower capital for some of our areas and more production. So that’s one of those good things you can have up.

Doug Leggate - Bank of America

And I want to go to the Fayetteville Steve, if I may. Looking at the IP rate to the latest parts of wells, the IP rate obviously fell a bit but the 60 day rate is up quite substantially now. Obviously there is issues with lots of [winds] there, but I just wonder if you could help walk me through that how that dynamic is changing, at least what the type curve is on these longer laterals is changing quite a bit compared to what we may be assuming currently. And obviously it looks like it’s got outside implication for the EUR, so can you give us an idea what’s going on there between the lower to up front rate and the significantly bigger 60 day rate? Thanks.

Steve Mueller

Yes. I’ll let Bill address that.

Bill Way

Yes. Our IP rate by quarter is determined partly by where we happen to be drilling. So 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 continue to move around in 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 and we will continue to spread across the field additional testing with both high rate tests and resting of wells to pull the water off, which in many parts of the field is also contributing to increased rates.

Steve Mueller

Remember 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 is going to sustain yet or not, but certainly some of them are. So I would guess another, we need another couple of quarters before we can say yes, we are getting more reserves and better wells out of them. But it’s sure interesting today.

Doug Leggate - Bank of America

Steve is there a way that we can figure out what proportion of your drilling backlog is going to, is it now longer lateral type design versus the more I guess the standard wells you had for you, you would say?

Steve Mueller

There is really not, it’s really not just the longer laterals, so it need to be a little bit careful there, but some are doing 20% and 25% of this year’s drilling across the southern part of the field doing these kinds of things.

Bill Way

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

Doug Leggate - Bank of America

That’s helpful, thanks.

Operator

Next question is from the line of Gil Yang with DISCERN. Please go ahead with your question.

Gil Yang - DISCERN

Thanks, good morning. To follow-up on Doug’s question, the 20% to 25% of the wells doing these kinds of changes to the completions into the designs, is that -- if everything works sort of as you might best plan will it all be 20% to 25% limited by the geology or could it be substantially higher proportion of the wells that you are drilling?

Bill Way

As I think Steve mentioned, it’s probably a bit too early to tell. We’re 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 tried to say is that, let’s keep IPs on trend, but we are going to continue to test this and for a field that has the number of wells that we’ve drilled in it 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 sustain 30 and 60 day rates and just please stay tuned on that and we’ll keep bringing that news to you.

Steve Mueller

Let me just add that you’ll see our Investor Relations material here in a couple of days. I got a glance at it last night and for those who have seen them in the past, we’ve got where we’ve drilled in last 12 months and we’ve got stars on the map where it’s 3 million and 5 million a day. Going back to Bill’s comments you’re going to see a lot of stars on what people thought were the edges on the field. And so there is some different geology. And then just to remind everyone, there is the well resting that Bill talked about. That doesn’t necessarily match with the geology, and there’s surface things we’ve done to debottleneck, and that doesn’t necessarily match with the rest more than the geology.

So it’s a combination of all those things and just stay tuned. I think the big thing is that the Fayetteville Shale is continuing to get better and for 2014 I can comfortably say the kind of performance we had in the last couple of quarters last year will continue through 2014 and I want to see what happens as we go in future.

Gil Yang - DISCERN

Great. My second question is related to all this is given the changes in the completion designs and the improvements you’ve seen or you think you’re 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’re using to select locations in the inventory and are we seeing that already? Or is that sort of yet to come?

Bill Way

Well 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 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 is opportunities to increase density of pad drilling to lower cost or things like that we’re obviously looking at that, but I wouldn’t say there is any kind of wholesale change at this point.

Steve Mueller

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 in our pad. We went back to full pad drilling really probably in the third quarter of 2013. So we’re not necessarily high grading wells, we’re certainly testing areas we’re not high grading wells, we are drilling pads out.

Bill Way

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

Gil Yang - DISCERN

Great, thank you.

Operator

Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please go ahead with your question.

Dan McSpirit - BMO Capital Markets

Thank you. Folks, good morning. 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. And can it and may be should it be applied to different parts of the basin.

Bill Way

We are testing resting of well across the basin. So that process and project is ongoing. We get two benefits from resting of wells. The first benefit is through water that normally flows back with these wells when they are brought on immediately is retained in the reservoir.

And so the lifting cost associated with these wells goes down the management of the water at the surface is a 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 of water and increased production in additional parts of the field. So testing is fairly broad and we’ll continue to do that.

In terms of the increased EUR we began this testing program early last year and we’ve got some additional run time to go to determine whether there is additional EUR associated with that. Certainly we are able to get additional volume where it happens out, does value out in would need us to continue to test that to be certain.

Dan McSpirit - BMO Capital Markets

Okay, great. and as a follow-up, if you can 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?

Bill Way

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

And some of the lateral lengths are extending, but the real key is the area that we are doing a lot of the drilling in and 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.

Dan McSpirit - BMO Capital Markets

Thanks, again.

Steve Mueller

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

Dan McSpirit - BMO Capital Markets

Got it, thank you.

Operator

Our next question comes from the line of David Heikkinen of Heikkinen Energy. Please go ahead with your question.

David Heikkinen - Heikkinen Energy

Good morning, guys. Just wanted to quantify one thing in the first quarter how much of an impact that you have in the Fayetteville harsh winter condition, like do you have any numbers that you can put to that?

Bill Way

All in the three major ice storms that we had it satisfies about 1.7 Bcf, the team were able to claw by back to the point where we got, we met to the target that we set out. So big issue was ice we have winter weather everywhere in our operation, but Arkansas was particularly hit with ice so the a ability of move around but at any one-time I think we had in one instance like we had 800 Bcf off the table, but came back after few days.

David Heikkinen - Heikkinen Energy

Okay. And then…

Steve Mueller

To jump, Bill hesitates before he answers a question. One thing I could tell guys around here is our job is to give results, not have excuses. So I had a (inaudible) to tell me you could talk about the result.

David Heikkinen - Heikkinen Energy

Thanks Steve. Then in the Marcellus, you talked about trying to reduce gathering expenses, as you go forward and you have a lot of growth coming can you talk about how much of the gathering expense reduction is just due to volume growth and how much of it actually renegotiating contracts and installing on equipment and kind of quantify the cents per Mcf impact on [LOE]?

Bill Way

Well, I guess what I would say in this regard, because we’re in active discussions, we are working with one of our third party gathers to look 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 volume has come up dramatically, excuse me, 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 in 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.

David Heikkinen - Heikkinen Energy

Okay. That was my two questions. Thanks.

Steve Mueller

You bet.

Operator

Our next question is from the line Scott Hanold with RBC Capital Markets. Please go ahead with your question.

Scott Hanold - RBC Capital Markets

Thanks, good morning.

Steve Mueller

Good morning.

Bill Way

Good morning.

Scott Hanold - RBC Capital Markets

When you look at I guess the forward gas prices and it seems like somewhere around $4.50 plus might be at least a kind of a reasonable range to think about. Specifically with the Fayetteville Shale, what is your current thoughts on potential like inventory counts at $4.50 plus NYMEX type price?

And if you could add on to that, where could it go with some of these drilling and improvements in cost savings that you’re seeing?

Steve Mueller

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

We do have the Upper Fayetteville, we mentioned that. And we don’t normally talk about that in our numbers, but I think on the lowest side you’re talking about 700 wells there and could be up over 1,000 wells before it’s all done in the Upper Fayetteville.

And then I’ll remind everyone that we still have the exploration acreage of a 170,000 of exploration acreage in the federal part of our acreage that we’ve drilled 11 wells on. We know at least a third of that looks good, but actually several years before we can get to it so that’s not in our work count either.

Scott Hanold - RBC Capital Markets

Okay, that’s good color. And maybe this is just sort of a bigger picture view and when you look at Fayetteville then what you describe is probably at least the 10 year inventory of joint opportunities there. And when you look forward to LNG being more important coming out of the U.S. starting in probably a year two, have you all stepped back and looked at the position the Fayetteville being able to access that area where you’d feel comfortable to maybe negotiate some of your volumes to that type of project?

Steve Mueller

We’re talking to a lot of people and I don’t know that we’ve got anything, I am not on it. But certainly power plants big manufacturing industrials or building new plans and LNG export all have need for natural gas. And the interesting thing about it is, when you’re start [planting] gas reversing out of Marcellus moving south, it goes right by the Fayetteville shale. Fayetteville shale is probably one of the best positions gas properties in the country for the new demand. And so we do talk to people, but I think we’ve got a premium asset there and it’s a right thing came along, we make a longer term deal, it’s not we’re excited about the Fayetteville and (inaudible).

Scott Hanold - RBC Capital Markets

I appreciate that. Thanks guys.

Operator

Next question is from the line of Charles Meade with Johnson Rice. Please go ahead with your question.

Charles Meade - Johnson Rice

Good morning, gentlemen. Thank you for taking my question. Bill, I think you did referenced in your prepared remarks about Marcellus that you’ve done some derisking there. And I’m wondering if you could add some specifics to that and I guess what I’m really after is maybe a review of your testing program in that Wyoming acreage and where you guys staying with that and if your plan to (inaudible) there?

Bill Way

Well, we have derisked about 44,000 acres of our acreage and done that across the fees, 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 have begun testing on, we have had a couple of different well results as we expect we would have with sort of that line of demarcation that runs right to 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 and then we have 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 is pretty early time.

Charles Meade - Johnson Rice

Typically Bill, we are all talking about vertical wells here right?

Bill Way

At this point.

Charles Meade - Johnson Rice

Right, okay. Thank you, that’s helpful. And then Steve, I was wondering, on your last call you offered some, you offered that your realizations up in the Marcellus have been good for the first two months of the year. And I am 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?

Steve Mueller

Yes. I think right now as we start paying attention to spot prices, the first quarter was good where first quarter were plus 15, I think it was in the Marcellus 15, so far in April it’s a minus number. And I think you are going to see a minus number as you go through the rest of the year. That goes back to my initial comments about guidance. So we want to see the gas price so we could start seeing if our guidance makes sense. If you remember our guidance was $0.55 to $0.60 negative for the company versus historical that was $0.45 to $0.50 type number. So we’re still watching I don’t have any magic news or anything that I can tell you that says $0.55 to $0.60 shouldn’t be a good number.

Certainly, first quarter was better than we thought, but there is a lot still to go and there is a lot different ways it can go.

Charles Meade - Johnson Rice

Thanks Steve. That’s it.

Steve Mueller

Thank you.

Operator

Our next question is from the line of Joe Allman with JP Morgan. Please proceed with your question.

Joe Allman - JP Morgan

Thank you hi everybody.

Steve Mueller

Good morning.

Joe Allman - JP Morgan

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?

Bill Way

Between now and the end of the year, as I said in my prepared remarks, by the end of the year we’ll have just over a $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. I would 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 called up with the idea of meeting firm transportation and so the cost of that has gone up significantly. In our minds continuing to add to affirm at those high numbers just doesn’t make sense at this moment. And 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’re 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, but we’ll 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 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 though our firm transportation realizing some fairly hefty margins as well.

So, we are keeping ourselves nimble up there, putting our ability to move the gas everyday and then now watching the market.

Steve Mueller

And I would say that any given day, you may have between 30 million and 50 million a day going into the spot market, anything you complete during the months is definitely going to spot market. On a long term basis, we don’t want to get more than about a 10% at the high end of that of wherever our production is and probably in the 5% range. So, you buy a firm, you want to make sure that you use the firm, so you can always make a little bit above it but we will just follow the firm curve.

Joe Allman - JP Morgan

So on that I think on March 31st, your gross production was 823 million a day, I think that was 200 plus million a day above your firm transportation firm sales, so could you explain how you are moving that?

Steve Mueller

Yes. I am not sure it’s quite 200 million a day, you got the most updated graph, but it’s probably a little over 100 million a day. We’re drilling like anyone else is, we’re selling it where we can sell it.

Joe Allman - JP Morgan

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

Steve Mueller

Yes. And I’ll just tell everyone, we have got -- with 118 million a day, we have got an updated curve. It’s smoother than the last one you saw that had little cliff on it right now and so our -- Brad will be happy to send that thing, and why don’t you shoot him an email. But if we put a pad on and the pad is 100 million or 50 million a day or 70 million a day for whatever period of time, we get some next months and you get it to the monthly sales, it’s spot sales.

Bill Way

At June we go up to 850. So, we’re -- a 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.

Joe Allman - JP Morgan

Great. That’s very helpful. Thank you.

Operator

Our next question is coming from the line of Brian Singer with Goldman Sachs. Please go with your question.

Brian Singer - Goldman Sachs

Thank you. Good morning

Steve Mueller

Good morning.

Brian Singer - Goldman Sachs

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

Steve Mueller

I think 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 add -- sands relatively expensive, it’s really the fluid pumping. But if you put more sand in it little more expensive, but it’s probably a well count thing more than it’s going to be and that really just goes back to rocks looking better in Susquehanna than we originally thought it was.

Brian Singer - Goldman Sachs

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

Steve Mueller

Again, simple to answer is that the big block we have in Northeast Susquehanna around New York boarder were about two-thirds away 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 stays that strong to that area. But it just -- 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 getting little bit of and it still might as we go forward north, we just don’t know yet.

Brian Singer - Goldman Sachs

Got it. But that’s the area for the upside surprises that northern blocks?

Steve Mueller

Yes. The Wyoming -- as I talked about for Sullivan we’re just in first passes of drilling well. So it’s I guess a couple more quarters before we can make even assessment of what we have got there.

Brian Singer - Goldman Sachs

Great. Thank you.

Operator

The next question is from the line of Bob Brackett, Bernstein. Please go ahead with your question.

Bob Brackett - Bernstein

Hi, good morning. Quick question on reserves. Back in 2012, you took a fairly large negative revision on Fayetteville gas, just on trailing price. Is that stuff reversed this year, if gas price hold up?

Steve Mueller

We -- if you think about 2013 bookings, in 2012, to put in perspective, we have about 1,500 PUDs on our books. At the end of 2013, I think we have about 1,200 PUDs on our book. So we got far way back in 2013 and then as price stays about $4, the average price in 2012 was 4.12 which should get most of that back on our books. So yes, you have continued reserves come back in our books from just adding price to the overall situation.

Bob Brackett - Bernstein

The other, 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 North Eastern becomes more and more important?

Steve Mueller

I don’t know we are branding so much -- we are SWN internally all time, so that this maybe the case. I can tell you that, we did try to copyright SWN and it’s already copyrighted, so I don’t that we’ll rebranding SWN.

Bob Brackett - Bernstein

Okay. So I’ll stick to the long one.

Steve Mueller

Thanks. Yes, just take a long.

Operator

Our next question is from the line of Tim Rezvan of Sterne Agee. Please go ahead with your question.

Tim Rezvan - Sterne Agee

Hey, good morning, folks. I was hoping to circle back on the theme of spending. It looks like you are going to have a pretty good free cash flow surplus this year. And you just choose the idea of maybe cutting spending a bit in guidance, this leaves you unlevered 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?

Steve Mueller

I think 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 and 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. And certainly as we test some of the exploration ideas and any of those work, those could be places to put capital not necessarily this year but in nearby future years. And then the Niobrara, if we can get all of the permits that we want, get all five wells drilled, there is 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 not updating guidance quite yet.

Tim Rezvan - Sterne Agee

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

Steve Mueller

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

Tim Rezvan - Sterne Agee

Okay. And then one last one on the acquisitions, unlike some other E&Ps that have really paid up a premium for kind of known derisk inventory, you’ve favored more exploratory acquisitions given kind of the head fakes we’ve seen at the Brown Dense, so just see uneven results. How do you think about buying exploratory rock versus getting something that you know you can develop going forward?

Steve Mueller

It’s a matter of what risk you take. Certainly, if you get in early in our first mover and do the exploratory part, it’s less expensive to gain to it, but you have that risk but it may not work. And as you said the head fakes of Brown Dense was in. We know internally that we’re 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. And 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. And when I say some of our skill set, we’re good at drilling wells and developing very large projects, and if it’s already half way developed because I took the risk out of it, and that took some of that learning things that we could have done and potentially done better. So we like getting in early, not necessarily, it doesn’t have to be just prior to exploration, but we like getting in early. Then applying that vertical integration, time logistics that we do and all the other things we’re good at to add a little bit extra that someone else can’t do.

Tim Rezvan - Sterne Agee

Thank you for color.

Operator

Next question comes from the line of Arun Jayaram with Credit Suisse. Please go ahead with your question.

Arun Jayaram - Credit Suisse

Good morning, gentlemen. Steve I also wanted to follow-up on that free cash flow question for some time you guys had been outspending cash flows as your kind of early stage of spending in the Marcellus, had some of the Brown Dense spending and then obviously the low gas prices. Now that you are essentially moving into kind of free cash flow mode. I was just wondering what the long term outlook 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. So just trying to get some thoughts around that?

Steve Mueller

Well, you can’t go further and outspend your cash flow. Some of it doesn’t work as you go through it. But our goal is to have more projects when you have capital you don’t have to worry about how you make those projects work. So we are still on a go and we’ll still do the exploration on 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 and then you have to figure what you are going to do. And 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’t go faster there we just have to be certain that we don’t think this price today.

Arun Jayaram - Credit Suisse

So Steve if you are going to add incremental capital into your businesses sounds like it would go into Fayetteville ahead of the Marcellus is that fair?

Steve Mueller

It would today, it may not in a couple of years if we are going back to the tracks we want to follow at front curve. We put all the capital we can to it right now to follow that front curve. There isn’t much more we can do there.

Arun Jayaram - Credit Suisse

Okay. and just my follow-up is just on the cost to 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 kind of market prices or additional firm?

Steve Mueller

The line that’s assigned firm depends on where it’s going and how many sales points it has. It’s the one with single sales point and it’s not a really good sales point and no one is going to pay a lot for that. But to put it in perspective, our average all-in price out there is just something over $0.30 for the transportation that we have to-date and looking at some of the projects that are out there. There are several projects that are $0.70 amount type projects and there are some at size $1 amount. And in some cases that would make sense because they are going to very high quality markets and 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 makes sense or not for us as a company.

Arun Jayaram - Credit Suisse

Alright, thanks a lot.

Operator

Our next question comes from the line of Michael Rowe with Tudor, Pickering, Holt. Please go ahead with your question.

Michael Rowe - Tudor, Pickering, Holt

Hi, thanks, good morning. I was just wondering, if you could just provide an update on where you expect your firm transportation to be in the Marcellus as of but I guess or if the cadence throughout 2015 with these recent additions?

Steve Mueller

I don’t have the exact number in front of me but I think it would be less than 1.1 Bcf a day till the end of 2015.

Michael Rowe - Tudor, Pickering, Holt

I was just wondering, is there any way you could provide any additional color on which markets you’re delivering gas to by hub in the Northeast?

Steve Mueller

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

And so in general, I think we can tell you that we’re trying do the points of a compass and going several different directions and kind of even that out over the next two to three years. But anyone who is 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 a surprise as the year rolls out.

Michael Rowe - Tudor, Pickering, Holt

All right. Thank you.

Operator

Our next question is from the line of Stephen Shepherd with Simmons. Please go ahead with your question.

Stephen Shepherd - Simmons

Hey, good morning guys. My Fayetteville and Marcellus questions have been answered, but I was just wondering is there any intention to add any more frac spreads this year to the two that you currently have?

Bill Way

At this point, no. We haven’t made a decision on that. I mean, what we do is we look at our utilization. We look at projects that we have and we look at the sort of the activity level that is in by play to make sure that if we were to add any kind of additional equipment, we get 100% utilization out of it.

So for example, we’re looking as a part of the whole Niobrara evaluation, how far do we take vertical integration into that play. Should that play be successful? So there’s lots of evaluation 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.

So we’ve been able to bring down the cost of fracing, drilling everything because of the presence of our vertical integration businesses. So say 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.

Steve Mueller

To put for instance a frac spread to work, it’s working 24 hours a day in the Fayetteville and then quite be the same on all of plays with the 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 wells (inaudible) pits for several years and then you start talking about any frac spreads, we’re not quite there yet.

Stephen Shepherd - Simmons

Okay that’s great, thanks. And one more for me, can you provide any more detail about the new ventures testing programs for later this year as you talked about the five well program of a horizontal and four verticals that you have. Where specifically on your acreage are those wells going to be drilled, have you figured that out yet. Is there any sort of intriguing offset operator activity that’s driving those decisions to drill in any certain areas. Just trying to get some thoughts on that, just anything additional to add there.

Steve Mueller

Yes, you’re talking about the Niobrara.

Stephen Shepherd - Simmons

Yes.

Steve Mueller

I think there is only one offset operator that’s doing things, it’s a private company on a demo called Axia. I don’t know exactly what their program is but they are deeper in the basin for the most part, dry gas with a little bit of liquids in one of their wells. We’re going for liquids window that will have some gas with it and so the intriguing part and the thing we are watching for, these wells are set up to go both laterally and across that window and fine tune where that window wanted to be and what effective that window is. So there aren’t really other operators right there do anything but each well will tell us a little bit about how big it might be and the quality of it.

Stephen Shepherd - Simmons

Okay, thank you.

Operator

Our next question is from the line of Jeffrey Campbell with Tuohy Brothers. Please go ahead with your question.

Jeffrey Campbell - Tuohy Brothers

Good morning. Just to jump back on the Niobrara that you were just talking about, you said there is not a lot of offset, operators have 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.

Steve Mueller

There were several wells drilled, some were drilled all the way back to 20s and 30s where there some conventional production out of Niobrara out of structural traps. When I say conventional it was actually fractured Niobrara but it produced out of structural traps. There were some wells drilled by Quicksilver and Shell over the last two to three years. That well weren’t in the locations that we wouldn’t want to drill and weren’t even really tested the way we’d want to test, gave us a lot of geologic information and the key wells have made us excited about the play where these wells drilled in a gas window and a lot of the gas window make excited we have mapped up the area projected that it was not going to be gas, it kind of confirmed our thought process in the play and that’s what got us to a pick up the acreage and go from there. So in the general area there is probably, most of 100 different wells drilled in most of those are going those conventional structures from the past.

Jeffrey Campbell - Tuohy Brothers

Okay. Great thank you that’s helpful. And I missed the first part of prepared remarks. So I apologize if I am asking first and then sorry if undisclosed but could you give you an update on the DJ Basin please?

Bill Way

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 from Marmaton and Atoka to again look at oil cut and test our process, we’ve got some wells to follow along to find that depending on that outcome of this next test.

Steve Mueller

And to remind everyone, we drilled two wells, best we have is about 140 per day oil rate, but had the water, and we’re actually going deeper into the basin, and hoping that we get rid of that water, and if get rid of water then we could have a commercial place. So it will take one or maybe two more wells to figure out (inaudible) there.

Jeffrey Campbell - Tuohy Brothers

Thanks very much I appreciate that.

Operator

Our next question is from Subhash Chandra with Jefferies. Please go ahead with your question.

Subhash Chandra - Jefferies

Yes, thanks for squeezing me in. I guess the first question is one of context and to revisit free cash flow theme. It seems like I see parallel here in the Barnett as in the Fayetteville where but you did see leading edge wells improve and become more efficient, but Barnett was in production of one up and but you can keep production flat with 10% of the rigs. So, when I see sort of these developments in the Fayetteville, I know you’ve talked to maybe accelerating activity in the hurdles and doing that. But is there a view that you might see this thing as really a cash cow overtime and where the hurdles are so high $5 to $6 gas for acceleration or is that too extreme of you for the Fayetteville?

Steve Mueller

I don’t know about extreme view or not, but 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, we need over $100 million per year. So really there was no decision or discussion until very recently there you have enough money to even add a rig and a rig will add about 60 wells a year to a program. So we’ve intentionally leveled in cash flow. We have done it for two reasons; one, you got to get to a point where you do that on each of your projects and you generate the excess cash like so they can fund exploration and other things you are doing.

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

As far as growing the Fayetteville Shale or not growing it, it is as you said like the Barnett. We have got, I think it’s hurdle in the play and it’s really us drilling with eight wells capable of horizontal production and if we double that rig count, that production will go up. So it’s really just a matter of capital and rig count that drives really have slight production or increase in production.

Subhash Chandra - Jefferies

Okay. And a follow-up, your reference quick silver and shale wells and it wasn’t clear from taking to quick silver, but were those wells in the fractured Niobrara. Did you sort of hint that maybe they were unstimulated, under-stimulated or what were shortfalls of their locations and completion designs?

Steve Mueller

Both of those companies took slight different approach to each other with certainly (inaudible) different approach to what we were doing. They were working around these fields over there. They were under the thought process that if you put water on the formation (inaudible) formation. So accept for I think it was two fracs in a quick silver well, all the well that shale and quick silver drilled were fraced or were fraced with butane or something else really put no water on the formation and didn’t get really get fracs away. Exit is coming down dip if thick water fracs and (inaudible) formation is not susceptible to damage.

So we’re looking at it as a more conventional, unconventional where they though there were some rock characteristic issues and we’re looking for natural fractures around these fields. So, it’s a completely different concept.

Subhash Chandra - Jefferies

Okay. If I can just add something like a, was that the clear content they shared?

Steve Mueller

Yes. And it is actually a paper written back I think is back in early 70s that said the Niobrara had clay in this area and you have to be careful about it. We have not seen anything in the quarter as again certainly the recent fracking verifies that. We haven’t seen that characteristic so we don’t know exactly what that paper was written with was or what the characteristic were that made that paper happen that way but that was the thought process.

Subhash Chandra - Jefferies

Understood, great. Thank you very much.

Operator

And next question is from Joe Magner with Macquarie Group. Please go ahead with your question.

Joe Magner - Macquarie Group

Thanks for making room. I know we are running late. Just one quick question some of the concepts in new well designs and completion techniques some other testing are those enough in enough themselves to perhaps go back to the drawing board and revaluate plays that either similar thought not to work of the 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 quality is still going to be the key differentiating factor and these are just going to be used to enhance results, just curious what your thoughts are there?

Bill Way

I think, I would 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 are certain thought processes on how you completed wells, it’s different than it was even 18 months or two years ago. And so yes I think you can go back and start reevaluating plays that may not have worked or plays that worked, but you might be able to get them extended out a little bit farther as it goes through.

I haven’t seen anything that we have done that’s is radically different so here is a new play and you got to go into it, but we are doing some fairly viable experiments in some of our fracs. So I don’t know that that won’t happen.

Joe Magner - Macquarie Group

Great. That’s all I have got. Thank you.

Operator

Our next question is from the line of Sameer Uplenchwar with Global Hunter. Please go ahead with your question.

Sameer Uplenchwar - Global Hunter

Good morning guys. Thanks a lot for taking my question. Quick question on trying to understand on Brown Dense, did you mentioned earlier that you’ll have a decision by 2Q or is the timing a little bit 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’re looking at other plays. Are they natural gas plays, liquids plays, and also are they in the lower 48 or internationally? Thanks a lot.

Steve Mueller

Let me start with the new ventures. New ventures we will roll out a couple of new plays during the year and at the moment we do that we will talk about them at that point in time. Any point in time we’re working on 8 or 9 ideas, some of those ideas are gas and some of them are liquids. So internally we don’t separate our gas and liquids. We just look at economics. And I talk people all time if we could find another Marcellus, I would love to find another Marcellus. So we don’t do anything from that perspective.

From international versus U.S. everything we’re doing right now is in North America. And I remind everyone we’ve got new (inaudible) as well. But it doesn’t mean someday we won’t be international just right now [our loving ones] are working on our North America.

Going back to the Brown Dense and one will know something. I know, I saw some things written today about well this latest well has a low rate. That’s not even the issue. The issue with the latest well is that it’s a mile away from our wells. It’s very economic and it has black oil in it. The well where we are 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 and the other doesn’t look like it’s water washed.

So there is a very complex history in the Brown Dense and I kind of put it in the category of the bully. Sometimes I’ll tell you that when the bully comes up, the thing to do is go fight him. But you don’t want to do that too many times as you get beat up too many times if he keeps beating you up. And right now Brown Dense has beaten us up.

And so I don’t know how long we’ll take the beating. Maybe it’s a quarter, maybe it’s two quarters, but not too far out. And yet we’ve got a good well. There’s another well that the industry drill it’s good well or some wells the industry is drilling in the area, and we’ve got some more ideas, and I don’t want to go in those ideas, because they could have consequences for other plays, but we’ll continue to work on it. But we’re not going to talk much about it.

So if you notice Bill didn’t say anything about it. We had one paragraph and you’ll see in our Investor Relations, that’s kind of going back at the Investor Relations and look what it says from here on and we’ll just keep working on. If we find something good, we’ll tell you. And if not, so that’s just from the Brown Dense standpoint.

Thank you.

Operator

Our final question comes from the line of Joe Allman with JP Morgan. Please go ahead with your question.

Joe Allman - JP Morgan

Could you talk about how constrained your production growth is in 2015 and beyond given firm transportation and firm sell agreements you have in place right now? I haven’t seen the latest spreadsheet, but and then you also talked about your expectation for adding additional firm transportation or firm sells in 2015 and beyond.

Steve Mueller

Well, we haven’t guided or even talked much about 2015. So I don’t know whether it’s constrained or are we going to grow rapidly or we’re not going to grow rapidly. Stay tuned on that part. As far as firm capacity and what we’re going to add in 2015, there is not much out there frankly, so I wouldn’t expect much more than we have now. We keep chipping away and well we added that $118 million this time. But we’ll keep chipping away, there is not a big amounts that are kind of available in 2015.

The new capacity that we were talking about is something beyond 2015 and really frankly beyond 2016 and 2017 as it goes through from the Marcellus. But don’t just assume the Marcellus may flatten a little bit on the firm, don’t assume that means the company is going to flatten, there is a lot of different options we have. So again stay tuned for 2015 we’re still trying to fair our guidance for 2014.

Joe Allman - JP Morgan

But as of right now by year-end you expect to be over Bcf per day growth, I mean is there a possibility in 2015 is flat from there. Or no, I mean …

Steve Mueller

Just stay tuned. I don’t know enough yet.

Joe Allman - JP Morgan

Could you describe the other options you have aside from the additional FT in firm sales?

Steve Mueller

Well, the biggest option you have is slow down your capital and just follow the 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 knew with economic, we’re going to know what makes sense and the growth rate will be the growth rate.

Joe Allman - JP Morgan

Okay, great, very helpful. Thank you.

Operator

Thank you. At this time, I’ll turn the floor back to management for closing comment.

Steve Mueller

Thank you. The average gas price through May averaged $4.84 this year and you only needs $3.40 average price for the rest of this year to $3 to $4 in 2014. If, I think back a year ago, that would have been almost an impossible discussion that you think about today. It was also seem highly unlikely the Southwestern Energy would generate $25 million of free cash flow above our investments in the first quarter of 2014. And was even more improbable that we would hit the capital efficiency so strong that we maybe going to incorporate a large part of our $180 million acquisition in our current capital budget and still beat our original production guidance.

As we’ve demonstrated this quarter and really over the last few years. We’re designed to provide good returns in low price environments and great returns on this $4 gas. We continue to believe that true success starts with curiosity and curiosity leads the learning, learning leads to new ideas, new projects and new ways of doing things. And I think as you seen in today’s conversation and our press release, all of those things are happening as what we’re doing.

And then true success and going back to the last question isn’t talking about or targeting growth rates, it’s based on firm economics. And I think we’ve shown a disciplined approach to delivering those above average economics and 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. And 2014 is going to be fun for us and for you and so stay tuned. Thank you for listening. Have a great weekend and that concludes our call.

Operator

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Source: Southwestern Energy's CEO Discusses Q1 2014 Results - Earnings Call Transcript

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