Southwestern Energy's CEO Discusses Q4 2013 Results - Earnings Call Transcript

Feb.28.14 | About: Southwestern Energy (SWN)

Southwestern Energy Co. (NYSE:SWN)

Q4 2013 Earnings Conference Call

February 28, 2014, 10:00 AM ET

Executives

Steven Mueller - President and Chief Executive Officer

William Way - Executive Vice President and Chief Operating Officer

Craig Owen - Senior Vice President and Chief Financial Officer

Brad Sylvester - Vice President, Investor Relations

Analysts

Charles Meade - Johnson Rice

Gil Yang - DISCERN

Scott Hanold - RBC Capital Markets

Drew Venker - Morgan Stanley

Tim Rezvan - Sterne, Agee

Amir Arif - Stifel

Brian Singer - Goldman Sachs

Arun Jayaram - Credit Suisse

Mike Kelly - Global Hunter Securities

Vedula Murti - CDP Capital

Rehan Rashid - FBR Capital

Ray Deacon - Brean Capital

Operator

Greetings, and welcome to the Southwestern Energy fourth quarter 2013 earnings teleconference call. As a reminder, this conference is being recorded. I would now like to turn the program over to Mr. Steven Mueller, the CEO of Southwestern Energy. Thank you, Mr. Mueller. You may begin.

Steven Mueller

Thank you, and good morning. Thank you for joining us today. With me today are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; and Brad Sylvester, our VP of Investor Relations. If you have not received a copy of yesterday's press release regarding our fourth quarter and yearend 2013 results, you can find a copy on our website at swn.com.

Also, I'd like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors in the forward-looking statement sections of our annual and quarterly filings with the Securities and Exchange Commission. Although, we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Now, let's start. 2013 was record setting year for Southwestern Energy. Providing value plus for our shareholders was never more apparent. Not only did we achieve new levels of net income, EBITDA, cash flow, production reserves, we did that while keeping our costs low.

Fayetteville records were set through improvements to our completion techniques and we continued expansion in new areas in the Marcellus, while moving new concepts and new ideas forward. I am very proud of the efforts of our employees in 2013 and I am certain you will see even more value delivered in 2014. Bill and Craig will speak about these records and new ideas in a few minutes.

I'd like to address a few general items. Let's start with Brown Dense. As you remember, last quarter we discussed our first commercial well in the Brown Dense and we also discussed the many things that need to happen for us to accelerate our investments in this project. Since then we drilled five wells. Three of these were drilled to test the geologic and volatile liquids limits of our acreage in an effort to determine other response, potential lease explorations and renewals over the next few years.

It's becoming clear that the best production will be in the high pressure cell, first encountered in our third well and extending at least 12 miles past our commercial well, the Sharp 22-22-1. We are currently testing the first offset to Sharp well and find a pressure to stimulate another offset in March, so we will better be able to discuss the details and what it means to this play during our teleconference in April.

The second general issue I'd like to discuss is the concerns about gas price in Northeast Pennsylvania. Southwestern Energy strategy in both the Fayetteville Shale and the Marcellus Shale has been purchase from capacity in an effort to contact several liquid sales points and reduced the price volatility and hopefully reduce the sometimes large gas price basis issues.

As you'll see in the earnings release and the discussion with Bill and Craig, our front capacity along with marketing opportunities has serviced well both in the fourth quarter of 2013 and first two months of 2014. From our perspective these are the side benefits of a much broader and longer-term strategy.

We have known for several years, there will be short-term volatility and price as the transportation was maturing in the northeast and we are also know there is a high probability, we'll be drilling for 10 years from now on our acreage. So what we can only guess is where the gas will be needed 10 years from now or maybe even 20 years from now.

We continue to believe the right strategy maximize price throughout the life of our projects, as it creates many outlets to as many markets as they're economically feasible. We have accomplished that in the Fayetteville Shale and need only a few more pieces to fill out the Marcellus. Gas markets outside the Marcellus have also been making headlines recently.

And before I turn the call over to Bill and Craig, I'd like to review a few thoughts on the overall natural gas markets. While we enjoyed the higher prices created by a cold winter, I feel the same way now as I did in the winter of 2012. We just come through what was reported to be the warmest winter in the northeastern U.S. in over 80 years. The outcome was low dry down in the storage and earlier than normal injections, which resulted in gas prices breaking below $2 in April of that year.

My point, one season of cold or one season of warm weather does not break the gas prices that Southwestern Energy uses to make our decision, and it does not drive our company for the great year 2014 is shaping up to be. Certainly, the future looks brighter than the past few years. The industry will need to increase supply by approximately 4 Bcf today over 2013, just to refill the storage to acceptable levels and we were already seeing the gas supply and demand situation improving before the cold weather hit.

Both of these facts allow me to feel comfortable as NYMEX price has a good chance to average above $4 for the next several years, but I still believe a significant amount of new drilling can and will be done as price approach is $5. So while we are and will be enjoying the additional cash flow from the prices we've seen so far in 2014, we build our company to drive in a much lower price environment. If you see that in our 2013 markets, established the year with a NYMEX price average $3.67.

With that, I will now turn the conference over to Bill, for an update on our 2013 results.

William Way

Thank you, Steve. Good morning, everyone. To further elaborate on Steve's comments, 2013 was an exceptional year for Southwestern Energy, and I am extremely proud of the innovation, hard work and commitment that all of our teams demonstrated throughout the year.

I'd like to share with you a list of milestones that we were able to achieve during the year, all of which are truly extraordinary, including several new company records.

In 2013, we set a new record for production of 657 billion cubic feet equivalent, which is up 16% compared to last year. With our increased production in the fourth quarter, Southwestern Energy became the fourth largest producer of natural gas in the lower 48 United States. And just last week, we achieved a new milestone of 2 billion cubic feet equivalent of net production per day by the company.

We set a new record for prove reserves of approximately 7 trillion cubic feet equivalent, which is up 74% compared to last year. We achieved the lowest finding cost in our company's history at $0.56 per Mcf equivalent and the third highest reserve replacement in the company's history as well.

In the Marcellus Shale, our production from the area nearly tripled, while our reserves were more than doubled compared to last year. This translates to gross operated production having reached 700 million cubic feet of gas per day at the yearend. I would note here that we have eclipsed 750 million cubic feet of gas per day earlier this month.

In the Fayetteville Shale, we reached a milestone of 3 trillion cubic feet of cumulative production from our operated wells, since the inception of the play and our reserves in the area were also up 60% compared to last year. And for the year we achieved both, the highest initial production rate from well and the lowest average cost to complete that well in our history. In exploration, we continue to acquire new acreage and tested several existing and new plays, and have many more ideas to explore on the horizon.

And finally, our Midstream Services segment posted the highest EBITDA in its history and made very good progress on adding additional firm transportation out of the Marcellus to facilitate our continued growth of our production and our expanded acreage footprint. These accomplishments along with many other small victories that are too numerous to count, give me a great amount of pride in our teams.

In the Marcellus Shale we placed a total of 100 wells on production during the year, resulting in production from the area of 151 billion cubic feet in 2013, up 181% from 54 billion cubic feet in 2012. Gross operated production in the Marcellus was approximately 700 million cubic feet per day at the end of 2013 compared to approximately 300 million cubic feet per day at the end of 2012.

Total proved net reserves in the Marcellus Shale grew 141% to approximately 2 trillion cubic feet in 2013 compared to 816 billion cubic feet in 2012. To comment briefly on our reserves in the Marcellus, we're very encouraged by the potential size of the resource we've captured in our Pennsylvania acreage.

We've been drilling in Bradford County for over three years now. Our Blaine-Hoyd well in southern Bradford County, which we brought on last year, had a peak 24-hour rate of 20 million cubic feet per day of gas, was unbounded and was the first well in the section and is currently booked at 22.6 Bcf.

Based on production history, we feel confident of the resource we have in place in Bradford County. And we believe that average EURs in that area should be in the 12 billion cubic feet to 16 billion cubic feet per well range for a typical 5,000 foot lateral with a 1,000 foot well spacing. Today, we currently have booked gross proven reserves averaging 8.7 billion cubic feet per PDP wells and 7.2 billion cubic feet per well for PUD wells.

In our range area in Susquehanna County, we've been producing our core area for a little over a year now. Notable well results include our Seamen's well located in northern Susquehanna County, which was placed on production in November of 2013 and reached a 24-hour IP rate of 32 million cubic feet of gas per day. While we still need some time to understand all of our acreage in Susquehanna County, we are very encouraged with what we have de-risked today, which is about 40,000 acres.

We believe that EURs in this area should be similar to our Bradford County wells on average, in other words in the 10 billion cubic feet to 16 billion cubic feet per day range for a typical 5,000 foot lateral with a 1,000 well spacing. We have PDP wells in the Susquehanna County area on our books at around 7 billion cubic feet per well. With additional production history, it's likely that you will see our provisions in this area in the future as well.

All comments on resources and reserves apply to our lower Marcellus horizontal wells only. In 2014, we will begin testing the upper Marcellus in our Bradford County area.

On the new acreage we added into our Marcellus position in 2013, we've drilled two vertical science wells, one in Sullivan County and one in Wyoming County. We will drill a few more vertical science wells in both counties to further test the area, but we are encouraged with what we've seen so far today.

On the gathering side in Pennsylvania, our Midstream Company was gathering 366 million cubic feet of gas per day from 90 miles of gathering lines across our Marcellus acreage at yearend. Since inception, we've invested nearly $200 million in our gathering systems in Pennsylvania, and in 2013 we generated about $30 million of cash flow.

We added 16,560 horsepower of compression in Marcellus in 2013 and look to add a similar amount in 2014 with new compression plant to be added in both Bradford and Susquehanna County areas. We'll continue to add compression throughout 2014 commensurate with our planned production growth.

Over the past six months there has been a lot of discussion in the marketplace about expected production growth from northeast corner of Pennsylvania and the impact that this had on current firm transportation capacity and fuel prices in the area. Our gas marketing team has done an outstanding job of contracting additional firm transportation arrangements, which gives us access to better price points in the area.

In total, we added over 300 million cubic feet of gas per day of firm transportation agreements out of the Basin in 2013, enabling us to reach and sustain 1 billion cubic feet per day of contracted transportation by the end of the year. Our long-term average transportation demand rate is approximately $0.37 per Mcf.

And we protected approximately 58% of our Marcellus gas production in 2014 with financial and physical sales arrangements at approximately $0.13 per Mcf lower than NYMEX, exclusive of transportation cost. Our strategy of leading with firm transportation has paid off and continues to allow us to ramp our production from the areas significantly over the next few years.

We expect to have another year of very strong results in the Marcellus in 2014. Our gross operated production is expected to increase to over 900 million cubic feet a day by the end of 2014, and we'll continue to work toward finding additional marketing opportunities for our gas as the year progresses.

In the Fayetteville Shale, we placed 414 operated horizontal wells on production in 2013, resulting in production of 486 billion cubic feet in 2013. Importantly, we achieved this production last year with almost 80 fewer wells as compared to previous year, when we placed 493 wells on production, which is a true testimony to our growing capital efficiency in that business. Total proved reserves grew by 60% to 4.8 trillion cubic feet compared to 3 trillion cubic feet in 2012.

In 2013, our relentless focus on delivering more showed very encouraging results, as we began to make several changes to our completion and flowback procedures in certain parts of the play, which had meaningful impact to early production histories in several of our wells.

By experimenting with completions and flowback configurations, resting the wells for a short period of time before we place them on production, and further optimizing surface facilities, we have a seen a significant increase in initial gas production rates with lower volumes of produced/flowback water.

Initial production rates in the third and fourth quarters were the highest in our company's history, with our fourth quarter IP rate setting a new record of 4.9 million cubic feet per day, along with record 30 day and 60 day rates of 2.86 million cubic feet per day and 2.58 million cubic feet per day respectively, for wells that were placed on production in the quarter.

Nine of our top 10 highest wells in the history of the Fayetteville Shale were drilled and placed on production during the third and fourth quarters of 2013. We are currently examining additional opportunities across the play to perform these modified completion techniques this year.

We continue to work to drive cost lower as well and in 2013 we set a new record for the lowest average completed well cost in our history of $2.4 million per well. Our vertical integration in the Fayetteville, which includes drillings rigs, our company-owned sand plant, our two SWN-owned frac crews and other field services provide an average savings of approximately $390,000 per well. Our vertical integration is a key component of our industry-leading efficiency.

On the Midstream side, our gas gathering business in the Fayetteville Shale continue to perform well, on December 31 was gathering approximately 2.3 billion cubic feet of natural gas per day from 1,947 miles of gathering line. Our cumulative total investment in our gathering systems in Fayetteville is nearly $1.1 billion today, it is paid out, and in 2013 generated $310 million of cash flow.

Moving on to our exploration group. At December 31, we held 4 million net acres, representing several potential new projects for us, of which 2.5 million acres were located in New Brunswick, Canada and 460,000 net acres are in our Brown Dense project. Steve has already commented on the Brown Dense project, so I won't to go into that at this point.

In our Denver-Julesburg Basin play in eastern Colorado, we've leased approximately 302,000 net acres and tested two wells in the Marmaton and Atoka formations in the area. We plan to drill an additional vertical well in the area during the second quarter of 2014. We'll begin drilling on two to three additional exploration ideas in 2014 and will keep you posted of our progress, when the timing is appropriate.

In closing, I again want to thank all of our teams for a terrific job, well done. While we are extremely proud of our accomplishments in 2013, we believe that 2014 will be even better. We're very excited about the opportunities that lie ahead and sharing those with you.

I'll now turn the call over to Craig Owen, who will discuss our financial results.

Craig Owen

Thank you, Bill, and good morning, everyone. Our results in 2013 were excellent and driven by higher production volumes and higher realized gas prices over 2012 and our continued focus on lowering cost. Excluding certain non-cash items, we reported record net income in 2013 of approximately $704 million or $2 per diluted share compared to $487 million or $1.39 per diluted share in 2012.

Net cash provided by operating activities, before changes in operating assets and liabilities, was a company record at $2 billion, up 24% compared to 2012. In the fourth quarter, our net cash provided by operating activities of $538 million exceeded our capital investments by $59 million. Operating income for our exploration and production segment was $879 million compared to $543 million, excluding the non-cash ceiling test impairments in 2012.

For the year, we realized an average gas price including hedges of $3.65 per Mcf, which was up from $3.44 per Mcf in 2012. In the Marcellus, we estimate that our January and February 2014 realized gas price, excluding hedges is about $0.45 to $0.50 above NYMEX. We currently have 456 Bcf or approximately 61% of our 2014 projected natural gas production hedged through fixed price swaps at a weighted average price of $4.34 per MMBtu. We have also recently added 120 Bcf of natural gas swaps in 2015 at an average price of $4.40 per MMBtu.

Our hedged position combined with the cash flow generated from our Midstream gathering business provides protection on approximately 70% of our total expected cash flow for 2014. Our detailed hedge position is included in our Form 10-K filed yesterday and we continue to monitor the gas markets and we'll be looking for opportunities to add to our hedge position in 2015 and beyond.

We are proud that we were able to keep our cash costs very low in 2013 and our cost structure continues to be one of the lowest in our industry. With all-in cash operating costs of approximately $1.25 per Mcfe in 2013 compared to $1.20 per Mcfe in 2012. That includes our LOE, G&A, net interest expense and taxes.

Lease operating expenses for our E&P segment were $0.86 per Mcfe in 2013, up from $0.80 per Mcfe in 2012, primarily due to the increased gathering and compression cost associated with the Marcellus Shale, partially offset by decreased saltwater disposal costs associated with Fayetteville Shale.

Our G&A expenses were $0.24 per Mcfe for the year, down from $0.26 per Mcfe in 2012 and were lower due to decreased personnel cost per unit of production.

Taxes other than income taxes were flat at $0.10 per Mcfe in 2013 and 2012. Full cost pool amortization rate in our E&P segment decreased to $1.08 per Mcfe compared to $1.31 last year.

Operating income from our Midstream Services segment rose 11% to $325 million in 2013 and EBITDA for the segment was $376 million also up 11%, and as Bill mentioned, is a company record. These increases were primarily due to the increase in gathering and marketing volumes for our Marcellus and Fayetteville assets. We invested approximately $2.2 billion in 2013 and currently plan to invest approximately $2.3 billion in 2014.

At December 31, 2013, our debt-to-total book capitalization ratio was 35% flat from 2012. Additionally, our total debt-to-trailing EBITDA ratio was about 1x. Our liquidity continues to be in excellent shape, as we had $283 million drawn on our $2 billion revolving credit facility at yearend 2013 and we also had $23 million of cash on our books. We currently expect our debt-to-total book capitalization ratio at the end of 2014 to range from 31% to 33%.

Looking ahead to 2014, we are excited as more records are within site due to the combination of increased production, our low cost structure and what is shaping out to be another year of higher realized gas prices.

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

Question-and-Answer Session

Operator

(Operator Instructions) Our first question today comes from the line of Charles Meade with Johnson Rice.

Charles Meade - Johnson Rice

If I could ask two questions on the Marcellus. The first, on the table, you guys included in your press release on the 30-day rates by quarter, you had a really nice uptick in the fourth quarter with that average rate of 10. And I understand that part of that's going to be the Seamen well, but I think, even if you take that out, it's still a nice uptick. And I am wondering if you can talk about the cons of that, whether it's a shift in your geographic mix or maybe, I know the lateral lengths a little bit longer, if there is perhaps a different completion design you're using there?

William Way

Part of it is a geographic mix. As we shift to drilling more in our Susquehanna County area and beginning to develop that area of the business, and you look at lateral length differences in between there and our historically drilled Greenzweig area, you begin to see averages shifting around and it's mostly that. We believe that we've got the same potential, EUR estimates in both areas, but it's just our earlier days in the range area that are driving that average.

Steven Mueller

Let me jump in. You asked about are we doing something different on completions. We're really not in Greenzweig area, Bradford County, we think we understand what we need to do there and it's been pretty consistent for last year. We're obviously still learning in the Susquehanna Northeast corner area, and as we learn we may change things, but what we're really doing is just for the last six to eights months just transferring the knowledge we learned in Bradford over to Susquehanna. As we drilled out more you may see some changes.

Charles Meade - Johnson Rice

And then, I want to go back to a comment part of the Craig Owen's prepared comments. And I'm not sure, I got this right, I believe you said that the $0.45 to $0.50 above NYMEX. Was that for the Marcellus year-to-date or is that an expectation for the first half or maybe the full year?

Craig Owen

That is Marcellus. And that's just what we're seeing in January, February of '14. So it's not changing anything for the year, but it's what we're seeing early in 2014. And just a reminder, that's a realized pricing on top of NYMEX, but it excludes our hedge position.

Operator

Our next question comes from the line of Gil Yang with DISCERN.

Gil Yang - DISCERN

Could you comment -- you made good progress on your IP rates in the Fayetteville. Can you comment on what the impact is to inventory and returns and EUR is that you're thinking at this point?

William Way

I think there's a number of dimensions in there. First of all with lower costs and higher values realized price for gas, our inventory of drilling locations goes up and we add significantly to that. The opportunities to really bolster the IPs from these wells and pick up the productivity side of the wells is born out of an effort that we're trying across the Fayetteville Shale to optimize the completions, look at facilities, look at resting of wells et cetera.

And we've seen some rather remarkable improvements to those IPs, which I think adds to the topline of the business. It doesn't necessarily additional drilling locations, but certainly gives us confidence that there is more to get out of Fayetteville than we might have originally even been believed. And so as we continue to drive cost out and the more vertical integration, the more efficient we become, you'll get more well locations from that, you'll get better increased value as we go across the piece and drive the IPs higher.

I'll note that on extended wells shut-ins or these resting that I talked about earlier, there is a IP improvement component to that, which again, if that works in some of the less strong areas, you may get some well locations out of it from an IP perspective. But it also means that we don't get flowback water. And you drive out even more cost out of the cost of producing of well. So turn back can also lead to greater number of locations that remain economic.

Steven Mueller

When you look at where these wells are, there are some that people would call it traditional core part of our field, but a lot of this record wells are actually to the south, both southwest and into the southeast. And so going back to inventory, I don't know that how many more wells it will add, but certainly is an area where historically we had a lot lower well count and a lot lower well EUR, so there will be a change, I don't the exact answer to what the change will be.

Gil Yang - DISCERN

Are any of the performance revisions that you talked about in the year related to these higher IP rates? Or that's not at this point, part of the EUR increase?

Steven Mueller

The performance revisions will be a result of wells you had already drilled, so those will go back to the PDP base. And if we had to put on our book, that we had at one level and went up a little bit. But its basically you're just seeing the increase from a PDP basis.

Gil Yang - DISCERN

And it's just, along that line, this is a final follow-up. Can you comment on the IP rate improvements that you're seeing in early 2014?

William Way

We've had a couple of wells come on recently that have been above 10 million and 12 million a day and as we continue to refine this, and continue to spread the application of both resting wells and certainly this modified flowback techniques across these. I think you can expect to see IP rates on average continue to decline.

Operator

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

I just wanted to maybe delve into that question a little bit more on the PUD bookings. It went up I guess a little bit from where we had then. But when you look at some of these bigger wells that you're drilling, what's it going to take to really see those roll into proved reserves? Is it another year of history or some of these wells are more online or is that going to be just a gradual step up like we've seen from you guys over the last five to six years with the Fayetteville?

Steven Mueller

Are you talking about the Marcellus or the Fayetteville or both?

Scott Hanold - RBC Capital Markets

The Fayetteville.

Steven Mueller

I think what will happen and you said there was a gradual step up, if you look year-over-year, our actual PUD booking is down a little bit. 2012 was a high-grade year ceiling, yielding at 200 wells in your books. At the end of 2013, we had just under 1,100 wells in our books. Put that in perspective, at the beginning of 2012, before the gas price dropped, we had almost 1,568 PUDs in our book. So certainly, as price works above $4, I think these wells will come back on your books.

And then as these techniques can be applied across the field, you'll see the EURs in those individual wells raise that average also. But it won't be a step-jump change, it will be, as you described, a gradual change, because these are gradual type of things we're doing. And so that's probably a two or three-year type timeframe, not a single-year timeframe.

Scott Hanold - RBC Capital Markets

Yes, I guess that would be the same in the Marcellus, a very similar kind of mentality.

Steven Mueller

Almost same story. The only difference in Marcellus is we're earlier in the learning. Today, we only have just over a 150 PDP wells to base any kind of decisions about. And for instance, in the northeast corner of Pennsylvania, Bill said, we had 40,000 acres, we are very comfortable with. But we still have another 50,000-plus acres as we work towards New York to learn about this year.

So it will be a gradual shift up, as we get more and more information, especially in Susquehanna. And again, we've only had a year on the longest wells there. Those reserves will creep up. And we've got a history of that. If you look at the early days of the Fayetteville Shale, it wasn't until two to three years out, you had a good base before you saw the reserves actually start stabilizing and getting to a slow increase. And when you put that in the fact that we're just now starting the Sullivan and just starting Wyoming, our averages may bounce around for the next year or so in the Marcellus, on each of those areas it will continue to increase.

Scott Hanold - RBC Capital Markets

And as my follow-up, on the Brown Dense. It's been a bit of science project here for a good couple of years, and when do you think we're going to have really a sense of whether this is a go-forward part of Southwestern's portfolio or you need to kind of move on? Are we six months away from that or 12 months away from that? Can you kind of give us a sense at a high level, what the thought process is here?

Steven Mueller

You just asked one of the questions I get asked every day. The hope is you'll have the answer tomorrow, but each new piece of information gives you some knowledge that sets up and you can go faster or slower. We are starting to understand better where the best rock is. And so that's important and that was part of that five well program we talked about. As we look at, at what makes us invest more money and say go, we need a couple of wells that are consistent that are economic and consistent.

And I think over the next two quarters, we'll drill at least four to five wells around that Sharp area and we'll figure out if we have the consistency. If we do, we'll go faster. If we don't have the consistency, the question is, what caused that inconsistency and how can we get around. Is it mechanical, is it something geological, how that works. And until we get there I can't say how that works.

I will say, if you think about any of these plays, I don't care if you use the Marcellus, Fayetteville, Eagle Ford. I don't know many plays that are 13 wells in, had three that were paid out. One that's obviously economic of the one company drilled. We've got another one that's economic by a third-party.

So I don't know if it's a matter of just when, but there is certainly something there that has significant potential to it. And we'll keep, as I said in last conference call, we keep chipping away at it, because almost no play gives you this much good indications this early. And we haven't given up on it.

And certainly, the three wells I talked about, they were the long step outs. We knew those had higher risk. Those were exploration wells. Those were there just to figure out, is this acreage going to be worth anything or not. And in some cases we found that there was immature oil or less mature oil, and so that we could write off part of it. In other cases we're still in the question mark range, can we make it work or not, but it's not going to be as good as the central parts. So we moved backed in that central part.

William Way

And in the central part, since we last spoke, we've only drilled one and completed one well out of that inventory. So we've got another one pending completion and then we've got, as Steve said, the additional wells that that really focus us in on this core area to come.

Scott Hanold - RBC Capital Markets

So what I think I'm hearing then is you've got enough information where the reservoir is teasing you to keep going forward. And then what I am hearing then, I guess is that maybe in the next six to 12 months we're going to really focus in on the part of the Brown Dense you think will really work, is that a fair context?

Steven Mueller

That is an excellent summary. And I'll just add one other thing to it. Looking for consistency, if for instance, the next four wells were all for -- it shuts down, if the next four wells are all good, we're going full speed ahead second half of the year. So there is potentially end members -- the exploration curse always is, what happens if there's too good too bad, and we'll just see what happens if we get into that range.

Operator

Our next question comes from the line of Drew Venker with Morgan Stanley.

Drew Venker - Morgan Stanley

I was hoping on the Brown Dense, if you could provide some more color on those newest wells. Maybe if you could talk about how long they've been on production and maybe compare how the performance of that Milstead well compares to the Sharp well at the same point in time of its production life?

William Way

The Milstead wells have been on production a little over a month. It takes various wells almost 20 days before you start seeing any oil or any kind of gas. It took roughly 20 days to see that. Then you start getting the oil and gas, independent of wells you've looked at, you can have a fairly rapid increase in the production to some maximum rate or a little bit slower. This one is on a little bit slower side than the Sharp well was, but it's still increasing, its rate today though it's less than 100 barrels a day.

Drew Venker - Morgan Stanley

And Steve, at what point in time or how long does it takes for the Sharp well to reach peak production?

Steven Mueller

Peak production, sure, well, I don't have it right on top of my head, but I want to say it was within 15 days after we started getting oil.

Drew Venker - Morgan Stanley

And then, is there any reason you think the middle of the zone is producing more versus the upper part or maybe you have that mixed up?

Steven Mueller

The upper part certainly in the newest well is where we're getting most of our production. We are doing several tests, trying to figure out. Well, we have fracked the entire interval trying to figure out why that's the case, if it's really mechanically open and all kinds of things that you normally hear excuses from various groups, but we're just early stages, and so I don't have an answer yet, I'll certainly have an answer in three months.

Drew Venker - Morgan Stanley

And then back to the Marcellus. It sounds like they're conservative in your view. Do you think what you've booked for 2013 fully reflects your new completion designs and longer lateral or is there additional upside there?

Steven Mueller

It doesn't fully reflect it, because as you know under SEC rules, you have to be 90% certain. And part of that certainty is you have to have a certain lengths of time on wells, on their productions size of the equation. And you have to have enough wells in the area you're at, so book a significant number of wells.

We're not even barely booking on a one-to-one ratio, because we are spread out and we're growing that. And especially in Susquehanna, those better longer wells have only been on production less than six months. So we feel from a production that they're going to get better, they're going to upward revisions, but you just don't physically have the data being 90% certain, so you can call an SEC reserve.

Operator

Our next question comes from the line of Tim Rezvan with Sterne, Agee.

Tim Rezvan - Sterne, Agee

Just want to follow-up on the Brown Dense. Can you clarify if the wells four and five and the ones that you had mentioned in the release, are those the step outs from the Sharp or those going to drilled, the step outs going to be drilled shortly, like in the near future?

Steven Mueller

The fourth and fifth well since the third quarter, fourth is drilled, that's the Milstead, that's the one we were talking about. The fifth well is drilled, but not fracked yet. It will be fracked in March. And then we will drill 23, some three to four additional wells on top of that. So we'll have in the next quarter-and-a-half, two quarters, six plus wells around that Sharp well.

Tim Rezvan - Sterne, Agee

And then I've noticed that your net acreage position has been dropping off. It looks like there has been some lease expirees. Do you have any comfort in any kind of core area right now around the Sharp that you think -- I know you're still doing tests, but how much of that do you feel like could -- do you have any kind of conviction on right now?

Steven Mueller

I'll kind of answer two pieces to that question. Around the Sharp well, if you go from the Sharp well north and east, about three miles. There is another commercial well drilled by a third-party. If you go south and west to our numbers, three well are BML well, on a kind of a north, east, south, west trend, that's the 12-plus miles I was talking about where we have seen high pressure in wells. And then we've also seen production that would at least payout the wells. Even though, we had a lot of science or had issues with those wells to payout the total cost of those wells.

So there is certainly an area in there, that's 12 miles long. We've done a lot of seismic and other work and they could be anywhere from 90,000 to 150,000 plus acres and that's some of the things we have to learn about in some of these other wells we do around the Sharp this year. So there is a core area there, it could be bigger. And second half of the year is to help design how much bigger that's supposed to be.

And then you've talked about dropping the acreage. What we found is, for the most part, on the Arkansas side, the gravity of the oil is too low a gravity with the pressures we have there to get or we think going to be ultimately sustainable rates. So some of the multi acreage you saw or I think all that acreage you saw drop was on the Arkansas side. And you will some more acreage drop there this year.

The well we drilled right after the Sharp well that is off to be far west was to test the acreage right near a major faults trend called the state line trend. That well actually saw some water with completely different chlorides than anything we've seen before. And we think we're getting some influence out of that fault trend.

We may go over there and do some things again trying to figure out how that fault trend is affecting the acreage in that area, but we think that's a boundary. We think that's a boundary on that side. So we've learned a lot about acreage and to the extent that we have acreage either to the far southwest or to the north in Arkansas, a lot of that will be dropped over the next few years.

Operator

Our next question comes from the line of Amir Arif from Stifel.

Amir Arif - Stifel

Just a follow-up to the last question. In terms of the size of the circle to draw around the Sharp well, that the Milstead well, that was only 1 mile north of the first Sharp well. So just wanted to clarify a comment you made earlier, Steve, that it sounds like you did also complete the lower Brown Dense, it's just that the middle Brown Dense is only producing, is that right?

Steven Mueller

The entire well is fracked. We're getting most of the production out of the upper part of that interval, which is the first well. Usually when we frac a well, we'll frac in the middle part of the well. The Sharp was the first well we had ever fracked at very bottom part. If you remember, we had 170 barrels a day from it. This latest well fracked the entire interval. It's a first time that the middle and lower didn't contribute. So we're scratching, that didn't contributed much, so we're scratching our heads on that portion. And that's why I said there may be some mechanical issues.

Right now, if I was an investor, and certainly this is a company where we are at, I wouldn't try to hang any kind of hat on what's going on the Milstead until we get more production and get more history. It's so early, a lot of things could happen over the next 30 to 90 days. So like I said, just be very careful trying to just make an assumptions or judgment off of that.

Amir Arif - Stifel

And the second question, the $190 million in New Ventures, that doesn't include the Brown Dense spending. In the DJ, you've already drilled a two well, so I am just curious, is the remaining of that $190 million for new acreages or are you testing any third play in 2014 that you might have some results to disclose on in '14?

Steven Mueller

There is about $120 million in for acreage, and all of the others is either a little bit of seismic, but mainly drilling. And there are some other plays, you'll see rolled out this year that we'll drill on.

Amir Arif - Stifel

So that will come out in '14, in terms you'll fund some new plays?

Steven Mueller

Yes.

Operator

Our next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Just a follow-up on the reserve bookings practices in the Marcellus, just a little bit more clarity there. I think your PUD, EUR fell year-on-year in Bradford Count and Lycoming County, but you've highlighted in your comments, you always expect ultimate EURs in Bradford and Susquehanna County to be in the 10 Bcf to 16 Bcf range.

Can you just take us through what gets us from last year to this year? And then what specifically within the life of well performance is going to get us to a higher number? And I guess, that's a part of that, is there any discrepancy in terms of how you're thinking about things relative to your reserve engineers?

Steven Mueller

It's easy to say, we don't have any discrepancy between us and our reserve engineers. I don't know if anyone knows, but reserve engineers do look at 80% of our total reserves -- at minimal of 80% of our total reserves and do independent work on it. They don't just audit. They actually do the reserves and then we compare back, this year it was less than 5% variance in reserves. And they did both the Fayetteville Shale and the Marcellus, so they actually did like 95% of our total reserves. So there weren't any discrepancies at all in either of those areas.

Now, what makes us think that something is going to get better or how do we get there. Remember when we're giving, whether its PUD averages, whether it's PDP averages, it is what we think we're going to drill at that time. So if the PDPs, which they do, has a lot of wells in them that are less than 4,000 foot laterals, a lot of early wells there going, that average is going to be affected by that.

If the PUDs, in a certain area, as we go north towards New York this year, in the Susquehanna Northeast corner, our laterals in that area will actually be a bit shorter laterals. If you put a PUD on the book that says you go on the northern end of the acreage and it's a 3,500 foot PUD, a lot of that just becomes a mix.

And so again, I wouldn't worry about whether it's 7.5 Bcf or 8 Bcf on an average per well, you need to get a more granular on that. And I don't know that the investment community gets so easy down well-by-well in that granularity, we do that everyday in what we're doing.

When we look at internally, whether it's IP or EUR or whether it's frac stage or per lateral length, that is increasing in general in all of these areas that we're drilling. And so that's what gives us a confidence that in the Bradford area, where we've got a lot of wells on it that we know what they're all, what's it going to be.

And that in the Marcellus as it compares that to Bradford, as it compares from the southern side of they play, we have a year of production to the northern part of Susquehanna, where we only had a few months of productions, that those wells are going to be better in the future.

But again from an SEC standpoint, you can't extrapolate that trend or you can't use that trend. What you can use is the data you have and the current well you drill and the PUD that you put next to it has to be based on the date in that current well, not on what you hope that well is going to do.

Brian Singer - Goldman Sachs

So I guess on the point with regards to moving, say, into a little bit more towards the New York border is the way to think about is that, you're going to disproportionately have some of the shorter lateral wells that likely will have lower EURs in 2014? And then, as you go forward beyond that you would expect it to go more into development mode in the higher EUR, longer lateral, deeper areas. So that's part of the reason, it's just the geographic trajectory over time.

William Way

It's not just the laterals. As you go shallower towards New York, you are getting shallower and your pressures are a little bit less, so you are just a little bit less pressure, but yes. This year as we move north, we're still just holding acreage and proving up acreage for the most part of 2014, and that certainly will affect this year's PUD. That's why I said earlier, I think they're all going to creep up. But it's still two to three years out before you stabilize and get to the kind of numbers that I was talking about.

Brian Singer - Goldman Sachs

And your reserve engineers are on board with the 10% to 16% that you talked about as the ultimate averages for these areas?

Steven Mueller

Our reserve engineer is due reserves for a lot of companies in the Northeast corner. So, yes, they understand that upside and they also understand very clearly SEC rules.

Operator

Our next question comes from the line of Arun Jayaram with Credit Suisse.

Arun Jayaram - Credit Suisse

I was wondering, if you could update us on some of your activity in the upper Fayetteville? And if you made any reserves bookings related to there?

Steven Mueller

I'll let Bill answer that.

William Way

We did some testing last year and we have 19 actual wells planned this year to test in the upper Fayetteville. We think it's about 120,000 acres of area that this covers. I don't have any reserve booking information, but we have continued to make some good progress on upper Fayetteville, especially in the way we're drilling the wells and the amount of time that we are really hitting the landing zone and staying in zone, which is really a key to making those work. We're pretty encouraged by some of the results that we are seeing and we'll continue to test that going forward, and then figure out broadly and how we want to attack protect that.

Steven Mueller

And to remind everyone, on the last call and in our end of the year comments, when we did our guidance, we talked about having some wells in upper Fayetteville that were 5 million a day plus. Those have only been in production for few months. So I don't know what we've got in reserves, but it's the same kind of thing we just talked about. They're going to revise up as you get more production in the year.

Before that though, we drilled just over 20 wells and the best one in there was a 5 Bcf well. The average were very similar to the averages that we have in lower Fayetteville, they were 2.3 Bcf to 2.4 Bcf, and I think the worse well in there is just over 1 Bcf.

So when we talk about the 150,000 acres I think ultimately we'll be very comparable on a reserve standpoint to the lower. They will be spaced wider, because it's a little bit thin on the upper Fayetteville. So in the lower Fayetteville your spacing maybe 400 feet to 600 feet apart drilling we're at, here it will be about 1,000 feet apart in that the upper.

Arun Jayaram - Credit Suisse

Steve, just thinking about the way you produced your Marcellus wells. I know you don't put them on to compression seven or eight months later and you flow them against higher line pressures. Does that also impact your initial reserve bookings in terms of your reserve report, the way you produce them?

Steven Mueller

It certainly is a factor. You have to make an estimate of when you're put on the compression and to the extent that you're relying on declined curve and early days of declined curve, it makes a factor. Once we start understanding the bottom hole pressure, then when you put that in the equation, your reserves, it doesn't really matter what that back pressures you can get the reserve calculation. But in early day of well it is a factor.

Arun Jayaram - Credit Suisse

And just my last question Steve, just thinking about the summer in northeast basis, I know you have basis risk hedged for a lot of your volumes. But given the cold winter, inventory levels are low in terms of gas storage. What are your thoughts on how bad it can get this summer?

Steven Mueller

I'm feeling a little bit better than I did a few months ago, but I think the summer is going to be messy. And when I say messy, I've seen a lot of different articles and things that people have done on which point is going to be problemsome. And I'm not sure, we're smart enough to understand, which sales point is going to be the worst sales point in any point in time.

But there will be lead times during the summer, I think even with the fact that we have to get more in the storage, where the sales points are going to have very low numbers. And to extent that any of us in the industry have to sell to that point. And I think what we make is decisions about shutting the wells versus selling those points.

For us, we've got most of our gas going in the Tennessee gas line or a millennium line. For the most part, if one of the lines or sales points on one of those lines have an issue, we can get to the other line and get around it. If both of those lines have issues, we'll have issues in, I don't know how to predict, if that's going to happen or not. I can just say that we're preparing for that in that case and we'll do what we need to do at that point in time.

Operator

Our next question comes from the line of Mike Kelly with Global Hunter Securities.

Mike Kelly - Global Hunter Securities

I was hoping you could talk about the opportunity and really the key variables at play, as it pertains to adding firm transport in the Marcellus going into 2015, given your likelihood of your 1 Bcf capacity there earlier in the year. And specifically done a great job of locking in your differentials on transport to date $0.37 for this year is testament to that. Just wondering what the market looks like to lock in some prices going in 2015?

Steven Mueller

Well, we have 150 million a day that we'll -- I don't know, if we make in 2015 and that looks like 2016 or late 2015, that it's part of Constitution line. So that will go in and that's not part of what Bill talked about as 2015 Bcf a day numbers that we had planned later in the year, and assume that there are going to be some issues on that.

Then as you look at the general directions gas needed to go in the Marcellus, a big demand over the next three or four years, increase is in that Mid-Atlantic towards southeast part of the U.S. And many of those pipelines are pointing in that direction and people that are talking about going that way, we're talking to them about that.

And one of the issues that is out there that we're debating with is that some of that's pretty expensive transportation and you've seen some numbers up to $1 to move gas, and there's a lot of them in the $0.70 to $0.80 range. We're trying to figure out some other ways around that. And so I don't have any exact answers for you.

But from our perspective, we're willing to buy pipe, build pipe, figure out a way to get transportation, but the end result will be, it will be economic transportation. So I think you'll see us try to work back in the Mid-Atlantic is what we're doing. And what's interesting about that, and I remind people all the time, is works back towards Mid-Atlantic, the best gas out there, certainly becomes a Fayetteville gas, gives us a shortest gas to it. So we should get a little bit of benefit on that side as well.

Mike Kelly - Global Hunter Securities

And a quick one from me on the Brown Dense, your recent activities were focused on vertical drilling. Just wondering behind the scenes you've been really trying to tweak your horizontal approach to the play, and if we could see you guys attempt on a horizontal well at some point this year?

Steven Mueller

The horizontal, we've got one or two of them in the budgets later in the year, and we continue with these various wells to test, how to frac and what to do from a frac standpoint. For the immediate future, it's a lot cheaper to figure out what's going on with the vertical, so would see as new verticals. But in some of these cases we're actually doing verticals where the profit is, if something works well, we come back and do the horizontal. So I'll just say stay tuned on that part.

Operator

Our next question comes from the line of Vedula Murti with CDP Capital.

Vedula Murti - CDP Capital

Can you give us an update as to what the drilling plan is in kind of that leads to your current point of view on the paradox wells, I know it's kind of hard in terms of trying to figure out a consistency there? But what's kind of the plan for 2014 to evaluate that area?

Steven Mueller

The early plan for 2014 is watch the industry and see what they're doing. There is some wells being drilled, south of our acreage block. And then once we understand what the industry is doing, we can make decision about what else we would do. There is three different zones that you can go after and the group to south is going after two shallower zones in the Crane Creek that we went into. So I think you won't see us doing actually any drilling activity until the second half of year, if we do any at all.

Operator

Our next question comes from the line of Rehan Rashid with FBR Capital.

Rehan Rashid - FBR Capital

Just quickly on the any incremental thoughts on separating the Midstream business from the E&P business?

Steven Mueller

I think we get asked this question almost every quarter. But right now, we like the Midstream exactly where it's at. It continues to generate good cash flow for us. As I just said, on the Marcellus, we may have to do some other things just to get the gas where we need to get it to. And having that Midstream inside our company, I think it's better than having in some secondary part of the company. So right now, we don't plan to do anything with Midstream except enjoy the fruits of what we're doing and expand it.

Operator

Our next question comes from the line of Ray Deacon with Brean Capital.

Ray Deacon - Brean Capital

I was wondering if I could ask you about Sullivan County and your activity there and what your thoughts are about acreage there? And then one follow-up on the reserve question, I guess, I am not sure I fully understood the response as to why you seem to have so many wells that are above the 16 Bcf-type curve, yet the average well doesn't seem to reflect that?

Steven Mueller

Let me, Bill, talk about Sullivan here in a second. I'll try and get back to the type curve. We do have a lot of wells that are well above 10 Bcf and lot of them above 15 Bcf or 16 Bcf. Most of those are in Bradford County. And that's because we've been drilling Bradford County for two-and-a-half years now.

When you get in a Susquehanna, you've only had a year on it. And while there is some very good wells at Susquehanna and we have got some wells booked above '15, you've just got a very short history there. And so even if we have a 10 million a day well, it's only been on production for three months or four months.

We might think it's going to be a 10 Bcf or 15 Bcf and 20 Bcf well. But today, we can't book it at that. And then if you want to book an offset to that well, your offsets are going to be at whatever booked at PDP or less to be 90% share, it's usually the less part. And so that's just drive our average in general. And I know there is a little bit of variance and bounce around Bradford, but trust me that that is a very good area and you're going to see those numbers work up over the next year.

Now, I'll let Bill talk about Sullivan.

William Way

On Sullivan County, we're trying to delineate that acreage along with Wyoming and Tioga in our program this year. So we've got a 12 wells planned across those three Counties, which is about 85,000 acres of the land to look at delineating. We'll start with vertical wells, get the results and these would be test wells, with some a lot of science et cetera in them. And once we see those results kind of come in, we'll plan some horizontal test wells to follow that. And that will be spread throughout really the second and third quarters of this year. We've already drilled two. And that's we're evaluating the data on that.

Steven Mueller

Let me say though that we really like what we saw in that first Sullivan well.

William Way

Absolutely.

Steven Mueller

And the Wyoming well was offsetting some of the better wells in the trend and it look pretty good too.

Ray Deacon - Brean Capital

If it looks competitive with your other acreage, than you would have to build out some infrastructure? How long do you think that might take?

Steven Mueller

Our goal for 2014 is to understand what we have in Sullivan in particular. And hopefully about second half of the year, make decisions about build out and then development and actual production would be some time in 2015. That will be about the fast as you could go. And Wyoming, there is a gathering system there. So you'll see us later in the year drill some wells that will hook into that gathering system. But again, it's sizing to figure out the current gathering system is big enough or if it needs to be expanded. And then as we make that decision, we can go if it needs to be expanded. And again, second half of 2015 is when you'd actually see the build out of our production there.

Operator

I would now like to turn the call back over to Mr. Steve Mueller for closing comments.

Steven Mueller

Thank you. I think back on some of the questions we've had today. And there is certainly some little things here and there that that we can ask questions about. Part of that I think is, because we want to give out as much information as we possibly can, so you can understand what we're doing. And that causes more question some times, than it might not, if we hadn't given out the data. But one of the things I want to promise you is that we will continue to give you as much information as we can, so you can make the best decisions about investing in our company.

And I think we're a company that ought to be invested in. The 2014, September of this year will be our 10 anniversary for production from the Fayetteville Shale. And if you think about it, only the very bravest person whatever predicted that after 3,500 wells, 3 Tcf of gas production, we'd still be driving down cost, we'd still be having questions about how many fewer days you can put into it, which is to be setting well production records and we'd be improving the return on every dollar we invested.

I'm actually looking forward and already planning some celebrations for that 10 anniversary in September. But I'm actually lot more excited about what's going to happen in 2014. The Fayetteville Shale is continuing to improve, we discussed that. And I fully expected the IPs this year are going to be better than last year in that play. And we'll have days to drill go down and we'll have cost go down.

In the Marcellus, we're in the center of the premier dry gas play in North America. We're going to continue to drive down cost. We've got lot more acreage to test during the year and as we talked about we're going to see those bookings and all the things that go with that just get better as we go through.

And then, I'm confident we'll have more earnings, reserves, production records, what we said in 2014. And then you start talking about upside. Upper Fayetteville, we talked a little about that with the questions. We're going to drill 20 wells there this year, 15 to 20 wells. And I fully expect you'll see debt development program continue in the future. Upper Marcellus, we're doing our first test there. And we're doing it actually in the center part of the Marcellus and Bradford.

Now, you'll start seeing us work our way in the Susquehanna in future year, and I think you're going to have upside there. There is a Brown Dense, whatever you think about it, there is some good wells there and hopefully we can sort that out, and make it a viable play for us. Then we have our other current exploration acreage, we picking up. We talked about picking up more acreage with the dollars we have this year. And I would expect a few surprises as we go on. And as I started this conference call, it's all about delivering value plus for our shareholders. We did in 2013 and I'm confident we'll do it in 2014.

And so with that I'd like to hand the call today. I know a lot of you, you've been on near the end of the grind of the earning seasons, I hope you can enjoy this weekend and next couples of weekends as you go through. And that concludes our conference call.

Operator

Thank you, Mr. Mueller. This concludes our teleconference for today. You may disconnect your lines at this time. Have a great day.

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