SWN

Southwestern Energy Company

Q4 2013 Earnings Conference Call

Friday, February 28, 2014

Officers

Steven Mueller, President and CEO

Bill Way,  COO

Craig Owen,  CFO

Brad Sylvester,  VP IR

Presentation

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 year-end 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 and the Forward-looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. 

Although we believe the expectations expressed are based upon reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Now, let's start.

2013 was a 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, well, we did that while keeping our costs low.

Fayetteville records were set through improvements to our completion techniques, and we continue to expand to the new areas in the Marcellus while moving new concepts and new ideas forward.  I'm very proud of the efforts of our employees in 2013, and I'm 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 the 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've drilled five wells.  Three of these were drilled to test the geologic and volatile liquids limits of our acreage in an effort to determine how to respond to potential lease expirations and renewals over the next few years.  It's becoming clearer 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're currently testing the first offset to the Sharp well and plan to fracture 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's strategy in both the Fayetteville Shale and the Marcellus Shale has been to purchase firm capacity in an effort to contact several liquid sales points and reduce the price volatility and hopefully reduce the sometimes large gas price basis issues. 

As you will see in the earnings release and the discussion by Bill and Craig, our firm capacity, along with marketing opportunities, has served us well, both in the fourth quarter of 2013 and the first two months of 2014.

From our perspective, these are the side benefits of a much broader and longer-term strategy.  We've known for several years there would be short-term volatility in price as the transportation was maturing in the Northeast, and we also know there's a high probability we'll be drilling for 10 years from now on our acreage. 

But what we can only guess is where that gas will be needed 10 years from now or maybe even 20 years from now.  We continue to believe the right strategy maximized price throughout the life of our projects is to create as many outlets to as many markets as is 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 leave you with 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 had just come through what was reported to be the warmest winter in the Northeastern US in over 80 years.  The outcome was low draw-downs of 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 a day over 2013 just to refill to storage 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 that 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 the price approaches $5. 

So while we are and will be enjoying the additional cash flow from the prices we've seen so far in 2014, we've built our Company to thrive in a much lower price environment.  You can see that in our 2013 records, established in a year when the NYMEX price averaged $3.67.

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

Bill Way: Thank you, Steve. Good morning, everyone.

To further elaborate on Steve's comments, 2013 was an exceptional year for Southwestern Energy, and I’m 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 proved 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 year-end.  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 per well and the lowest average cost to complete per well in our history.

In Exploration, we continued 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 this 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 to 16 billion cubic feet-per-well range for a typical 5,000-foot lateral with 1,000-foot well spacing.

Today, we currently have booked gross proven reserves averaging 8.7 billion cubic feet per well for 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're very encouraged with what we've de-risked to date, 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 to 16 billion cubic foot range for a typical 5,000-foot lateral with 1,000-foot 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 upward revisions 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 be 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're encouraged with what we've seen so far to date.

On the gathering side in Pennsylvania, our Midstream company was gathering 366 million cubic feet of gas per day for 90 miles of gathering lines across our Marcellus acreage at year-end.  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 planned 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's been a lot of discussion in the marketplace about expected production growth from Northeast corner of Pennsylvania and the impact that this has had on current firm transportation capacity and field 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.

On long-term average transportation, demand rate is approximately $0.37 per Mcf, and we've 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 costs.

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 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.

9 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 costs 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 drilling rigs, our company-owned sand plant, our two SWN-owned frac crews and other field services, provided 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 continued to perform well and at 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 to date. 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 go into that at this point.

In our Denver Julesburg Basin play in Eastern Colorado, we've leased approximately 302,000 net acres and have 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 we'll 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 costs.

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 & Production segment was $879 million, compared to $543 million, excluding the non-cash ceiling test impairment 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 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 hedge 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 will 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 costs associated with the Marcellus shale, partially offset by decreased saltwater disposal costs associated with the 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 costs per unit of production.

Taxes, other than income taxes, were flat at $0.10 per Mcfe in 2013 and in 2012.

The full cost of 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 1 times. Our liquidity continues to be in excellent shape, as we had $283 million drawn on our $2 billion revolving credit facility at year-end 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 sight due to the combination of increased production, our low-cost structure and what is shaping up to be another year of higher realized gas prices.

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

Questions-and-Answers

Operator: Thank you. We will now be conducting the question-and-answer session. (Operator Instructions). Our first question today comes from the line of Charles Meade with Johnson Rice. Go ahead with your question, please.

Charles Meade:  Thank you, and good morning, gentlemen. 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 an average rate of 10. And I understand that part of that is going to be the Seamen well, but I think even if you take that out, it's still a nice uptick.

I'm wondering if you can talk about the components of that, whether it's a shift in your geographic mix; or maybe another lateral length is a little bit longer, if there's perhaps a different completion design you're using there?

Bill 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 early days or earlier days in the Range area that are driving that average.

Steve Mueller:  And I'll just jump in -- you asked about if we're doing something different on completions. We're really not. In the Greenzweig area of 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 6 to 8 months, just transferring the knowledge we learned in Bradford over to Susquehanna. As we drill it out more, you may see some changes.

Charles Meade:  It does look like encouraging early indications. Then I want to go back to a comment, part of Craig Owen's prepared comments, and I'm not sure I got this right. I believe he said 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 in 2014. 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 realized pricing on top of NYMEX, but it excludes our hedge position.

Charles Meade:  Right, right, so quite strong, and that's the clarity I was looking for. Thank you.

Operator:  Our next question comes from the line of Gil Yang with Discern. Go ahead with your question, please.

Gil Yang: Good morning, gentlemen. Could you comment, you made great progress on your IP rates in the Fayetteville. Can you comment on what the impact is to inventory and returns and EURs that you're thinking at this point?

Bill Way:  Yes, 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 the wells, etc. And we've seen some rather remarkable improvements to those IPs, which I think adds to the top line of the business.

It doesn’t necessarily add additional drilling locations but certainly, gives us confidence that there's more to get out of the Fayetteville than we might have originally even believed. 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 increased value as we go across the piece and drive the IPs higher. 

I'll note on extended well shut-ins, or this resting that I talked about earlier, there's an 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 a well. So in turn, that can also lead to a greater number of locations that remain economic.

Steve Mueller:  And I'll just add on the -- when you look at where these wells are, there are some that people would call the traditional core part of our field, but a lot of these record wells are actually to the south, both southwest and to the southeast. And so going back to your inventory, I don't know how many more wells it will add, but it certainly is in areas where historically, we had a lot lower well count and a lot lower well EUR. So there will be a change. I don't know the exact answer to what the change will be.

Gil Yang: 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?

Steve Mueller: The performance revisions would be a result of wells you'd already drilled, so those go back to the PDP base and if we had a PUD on our books that we had at one level and it went up a little bit. But it's basically you're just seeing the increase from a PDP basin.

Gil Yang: And then along that line, just a final follow-up, can you comment on the IP rate improvements that you're seeing in early 2014?

Bill Way: We've had a couple of wells come on recently that have been above 12 million a day, 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 the piece, I think you can expect to see IP rates, on average, continue to climb.

Operator: Scott Hanold, RBC Capital Markets.

Scott Hanold: 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 been, 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 more on line or is it 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?

Steve Mueller: Are you talking about the Marcellus or the Fayetteville or both?  

Scott Hanold: I'm sorry, the Fayetteville.

Steve Mueller: I think what will happen, and you said it 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, so you only had 200 wells in your books. At the end of 2013, we had just under 1,100 wells on our books. To put that in perspective, at the beginning of 2012, before the gas price dropped, we had almost 1,568 PUDs on our books.  

So certainly as price works above $4.00, I think there's wells that come back on your books and then as these techniques can be applied across the field, you'll see the EURs on 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 of the gradual type things we're doing. And so that's probably a two or three-year type timeframe, not a single-year timeframe.

Scott Hanold: And I guess that would be the same in the Marcellus, a very smart kind of mentality.

Steve Mueller: Almost the same story. The only difference in the Marcellus is we're earlier in the learning. Today, we only have just over 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 were very comfortable with. But we still have another 50,000 plus acres just 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 and you had a good base before you saw the reserves actually start stabilizing and getting to a slow increase. When you put that with the fact that we're just now starting on Wyoming, our averages may bounce around for the next year or so in the Marcellus; in each of those areas, it will continue to increase.

Scott Hanold: And then on the Brown Dense, it's been a bit of a 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, 12 months away from that? Can you kind of give us a sense at a high level, what the thought process is here?

Steve Mueller: You just asked one of the questions I ask every day. The hope is you have the answer tomorrow, but each new piece of information gives you some knowledge that sets up if you can go faster or slower. We're 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 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 it. Is it mechanical, is it something geological, how that works. And until we get there, I can't tell you 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 3 that were paid out, 1 that's obviously economic 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's certainly something there that has significant potential to it. And as I said last conference call, we'll keep chipping away at it, because almost no play gives you this much good indications this early.

We haven't given up on it and certainly the 3 wells I talked about that were the long step-outs, we knew those had high 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 part. So we'll move back in that central part.

Bill Way: And in the central part, since we last spoke, we've only drilled and completed 1 well out of that inventory. We've got another one pending completion and then we've got, as Steve said, the additional wells that really focus us in on this core area, to come.

Scott Hanold: So what I think I'm hearing then is you've got enough information where the reservoir is teasing you to kind of keep going forward and what I'm hearing then I guess is that maybe in the next six, 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?

Steve Mueller: That is an excellent summary. And I'll just add one other thing to it. Looking for consistency; if for instance, the next 4 wells were all poor, it shuts it down. If the next 4 wells are all good, we're going full speed ahead the 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 let's see what happens if we hit in that range.

Operator: Drew Venker, Morgan Stanley.

Drew Venker: 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?

Steve Mueller: The Milstead well has been on production a little over a month. It takes these 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 and depending on what wells you look at, you can have a fairly rapid increase in the production to some maximum rate or a little bit slower.

This one is on the 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: Steve, what point in time or how long did it take for the Sharp well to reach peak production?

Steve Mueller: Peak production at Sharp, I don't have that right off the top of my head, but I want to say it was within 15 days after we started cutting oil.

Drew Venker: Okay. Is there any reason you think the middle of the zone is producing more versus the upper part? I maybe have that mixed up.

Steve 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 -- we frac'ed the entire interval trying to figure out why that's the case, if it's really mechanically open and all kinds of things you normally hear excuses from various groups on. 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: Then back to the Marcellus EURs; it sounds like they're conservative in your view. Do you think what you booked for 2013 fully reflects your new completion designs and longer laterals or is there additional upside there?

Steve Mueller: It doesn't fully reflect it, because as you know, in our SEC rules, you have to be 90% certain and part of that certainty is you have to have a certain length of time on wells on their production side of the equation and you have to have enough wells in the area you're at to book a significant number of wells. We're not even barely booking on a one-to-one ratio, because we are spread out in where our drilling is at. And especially in Susquehanna, those better longer wells have only been on production less than six months.

So we feel from production that they're going to get better, there are going to be upward revisions, but you just don't physically have the data to be 90% certain so you can call it an SEC reserve.

Operator: Tim Rezvan, Sterne Agee.

Tim Rezvan: I just wanted to follow-up on the Brown Dense. Can you clarify if wells 4 and 5 in the ones that you mentioned in the release, are those the step-outs from the Sharp or are those, the step-outs, going to be drilled shortly, like in the near future?

Steve Mueller: The fourth and fifth wells 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 frac'ed yet. It will be frac'ed in March. And then we will drill between 3 to 4 additional wells on top of that. So we'll have in the next 1.5, two quarters, 6 plus wells around that Sharp well.

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

Steve 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's another commercial well drilled by a third party. If you go south and west to our number 3 well, our BML well, on kind of a northeast/southwest 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 that had issues with those wells, to pay off the total cost of those wells. So there's certainly an area in there that's 12 miles long. We've done a lot of seismic and other work and it could be anywhere from 90,000 to 150,000 plus acres and that's some of the things we have to learn about and some of these other wells we do around the Sharp this year. So there is a core area there, could be bigger and second half of the year will help design how much bigger that's supposed to be.

And then you talk 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 what we think are going to be ultimately sustainable rates. So most of that acreage you saw, or I think all of that acreage you saw drop was on the Arkansas side and you'll see some more acreage drop there this year.

The well we drilled right after the Sharp well that is off to the far west, was to test the acreage right near a major fault trend called the Stateline 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 the 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: Amir Arif, Stifel Nicolaus.

Amir Arif: Just a follow-up to the last question in terms of the size of the circle to draw around the Sharp well. The Milstead well though, that was only one mile north of the first Sharp well and so I just wanted to clarify a comment you made earlier, Steve. It sounds like it did also complete the Lower Brown Dense; it's just at the Middle Brown Dense is only producing, is that right?

Steve Mueller:  The entire interval was frac’ed.  We're getting most of the production out of the upper part of that interval, which is the first well when we -- usually when we frac a well, we'll frac in the middle part of the well.  The Sharp was the first one we'd ever frac’ed the very bottom part.  And if you remember, we had 170 barrels a day from it.

Amir Arif:  Yes.

Steve Mueller: This latest well frac’ed the entire interval.  It's the first time that the middle and lower didn't contribute or didn't contribute much.  So we're scratching our head on that portion of it.  And that's why I said there may be some mechanical issues. 

Right now, I wouldn't -- if I was an investor, and, certainly, us as a company where we are at, I wouldn't try to hang any kind of hat on what's going on in 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 say, just be very careful trying to just make an assumption or judgment off of that.

Amir Arif:  Okay.  And the second question, the $190 million in new ventures, that doesn't include the Brown Dense spending.  And the DJ, you've already drilled the 2 wells.  So I'm just curious, is the remaining of that $190 million for new acreage or are you testing any third play in 2014, that you might have some results to disclose on in 2014?

Steve Mueller:  There's 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 just to be rolled out this year that we'll drill on. 

Amir Arif:  So that'll come out in 2014, in terms of results on some new place?

Steve Mueller: Yes. 

Amir Arif: Okay. Thank you.

Operator: Brian Singer with Goldman Sachs.

Brian Singer: Just a follow-up on the reserve bookings practices in the Marcellus, just a little bit more clarity there.  I think your PUD EUR cell year-on-year in Bradford County and Lycoming County.  But you highlighted in your comments you obviously 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 the well performance is going to get us to a higher number?  And then I guess, yes, and then part of that, is there any discrepancy in terms of how you're thinking about things relative to your reserve engineers?

Steve Mueller: Well, it's easy to say we don't have any discrepancy between us and reserve engineers.  I don't know if everyone knows, but reserve engineers do look at 80% of our total reserves -- at minimum 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 it back. 

This year 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 wasn't any discrepancies at all in either of those areas. 

Now, what makes us think that something's going to get better or how do we get there?  Remember, when we're giving, whether it's 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, have a lot of wells in them that are less than 4,000-foot laterals, a lot of early wells, 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 little 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 mixed. 

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 them more granular than that.  And I don't know that the investment community needs to get down well-by-well in that granularity.  We do that every day in what we're doing.

When we look at internally, whether it's IP or EUR, per 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 the confidence that in the Bradford area where we've got a lot of wells on it, that we know what the ultimate's going to be, and that in the Marcellus, as it compares back to Bradford as it compares from the southern side of the play where we have a year of production, to the northern part of Susquehanna where we only have a few months of production, 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 that maybe you have in the current well you drilled and the PUD that you put next to it has to be based on the data in that current well, not on what you hope that well's going to do.

Brian Singer: Thanks. 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 it that you're going to disproportionately have some of these shorter lateral wells that likely will have lower EURs in 2014, and then, as you go forward beyond that, you would expect to go more into development mode and the higher EUR longer lateral deeper areas, and so that that's part of the reason is just the geographic trajectory over time?

Steve Mueller: It's not just the laterals.  As you go shallower towards New York, you are getting shallower and your pressures a little bit less.  So you are going to get, let's say, you are just because there's 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, in 2014.  And that certainly will affect this year's PUDs.  That's why I said earlier, I think they're all going to creep up, but it's still 2 to 3 years out before you stabilize and get to the kind of numbers that Bill was talking about.

Brian Singer: And your reserve engineers are onboard with the 10 Bcf to 16 Bcf range that you talked about as the ultimate averages for these areas?

Steve Mueller: Our reserve engineers do reserves for a lot of companies in the northeast corner.  So, yes, they understand that upside and they also understand very clearly SEC rules.

Brian Singer: Thank you.

Operator: Arun Jayaram with Credit Suisse.

Arun Jayaram: I was wondering if you could update us on some of your activity in the upper Fayetteville and if you made any reserve bookings related to there.

Steve Mueller: I'll let Bill answer that.

Bill 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're 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're seeing, and we'll continue to test that going forward and then figure out broadly how we want to attack that.

Steve 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 the upper Fayetteville over 5 million a day-plus.  Those have only been in production a few months.  So I don't know what we've got on 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 had drilled just over 20 wells, and the best one in there was a 5 Bcf well.  The average was very similar to the averages that we have in the lower Fayetteville. They were 2.3 to 2.4.  And I think the worst well in there was just over a Bcf. 

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

Arun Jayaram: Steve, just thinking about the way you produce your Marcellus wells, I know you don't put them on to compression 7 or 8 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?

Steve Mueller: It certainly is a factor. You have to make an estimate of when you're going to put on compression.  And to the extent that you're relying on declining curve and early days of declining curve, it makes a factor.

Once we start understanding the bottom-hole pressure, then when you put that into the equation, your reserves, doesn't really matter what that back pressure is, you can get the reserve calculation.  But those early-day wells, it is a factor.

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

Steve 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's going to be the worst sales point at any point in time. 

But there will be times during the summer, I think, even with the fact that we have to get more into storage, where the sales points are going to have very low numbers.  And to the extent that any of us in the industry have to sell to that point, I think when we make the decisions about shutting in wells versus selling to those points, for us, we've got most of our gas going into the Tennessee gas line or the 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. And 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.

Arun Jayaram: Thanks a lot, Steve.

Operator: Mike Kelly with Global Hunter Securities.

Mike Kelly: I was just hoping you could talk about the opportunity and really the key variables of play as it pertains to adding firm transport in the Marcellus going into 2015, giving that you'll likely hit your 1 Bcf of capacity there early in the year.  You specifically have done a great job of locking in your differentials on transport to date - $0.37 for this year's a testament to that.  Just wondering what the market looks like to lock in some prices going into 2015.  Thanks.

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

Then, as you look at the general directions gas needs to go in the Marcellus, big demand over the next 3 to 4 years, increase is in that mid-Atlantic towards southeast part of the U.S., and any of those pipelines that are pointed in that direction are 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 is pretty expensive transportation, and you've seen some numbers up to a dollar 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, but 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 suddenly becomes our Fayetteville gas because it's the shortest gas to it.  So we should get a little bit of benefit on that side, as well.

Mike Kelly:  I appreciate that color.  And a quick one for me on the Brown Dense, your recent activities have been focused on vertical drilling.  Just wondering if behind the scenes you've been really trying to tweak your horizontal approach to the play and if we could see you guys attempt another horizontal well at some point this year.  Thanks.

Steve Mueller:  You know, 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 a vertical so you'll see us do verticals, but in some of these cases we're actually doing the verticals with the thought that if something works well we'd come back and do the horizontal. So I'd just say stay tuned on that part.

Mike Kelly: Thank you.

Operator: Our next question comes from the line of Vedula Murti with CDP Capital.  Go ahead with your question, please.

Vedula Murti: Good morning.

Steve Mueller: Good morning.

Bill Way: Good morning.

Vedula Murti: Can you give us an update as to what the drilling plan is and kind of at least 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.

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

Vedula Murti: Thank you.

Operator: Our next question comes from the line of Rehan Rashid with FBR Capital. Go ahead with your question, please?

Rehan Rashid: Morning. Just quickly on the -- any incremental thoughts on separating the midstream business from the E&P business?  Thank you.

Steve 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 it in some secondary part of the Company.  So right now we don't plan to do anything with the midstream except enjoy the fruits of what we're doing and expand it.

Rehan Rashid: Okay. Thank you.

Operator: I'm showing time for one more question.  Our next question comes from the line of Ray Deacon with Brean Capital. Go ahead with your question, please.

Ray Deacon: Yes, hey, good morning, Steve.

Steve Mueller: Good morning.

Ray Deacon: 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'm 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?

Steve Mueller: Let me just have 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 and a lot of them above 15 or 16 Bcf.  Most of those are in Bradford County and that's because we've been drilling in Bradford County for two-and-a-half years now. 

When you get into Susquehanna you've only had a year on it, and while there's some very good wells in Susquehanna and we have got some wells built above 15 you've just got a very short history there, and so even if we have a 10 million a day well, if it's only been on production for three months or four months we might think it's going to be a 10 or a 15 or even 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 offset is going to be at whatever book that PDP or less to be 90% sure. It's usually the less part, and so that's what's driving our average in general.  And I know there's a little bit of variance and bouncing around in Bradford, but trust me that is a very good area and you're going to see those numbers work up over the next year.

Ray Deacon: Okay.

Steve Mueller: And I'll let Bill talk about Sullivan.

Bill Way: And on Sullivan County we're doing, trying to delineate that acreage along with Wyoming and Tioga in our program this year, so we've got 12 wells planned across those three counties, which is about 85,000 acres of land to look at delineating.  We'll start with vertical wells, get the results, and these will be test wells with a lot of science, et cetera, in them.  And then 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.

Steve Mueller: Let me say, though, that we really like what we saw in that first Sullivan well.

Bill Way: Absolutely.

Steve Mueller: And the Wyoming well was offsetting some of the better wells in the trend, and it looked pretty good, too.

Ray Deacon: Got it.  And if it looks competitive with your other acreage then you would have to build out some infrastructure, and how long do you think that might take?

Steve Mueller: Our goal for 2014 is to understand what we have in Sullivan, in particular, and hopefully by the second half of the year make decisions about build out, and then development and actual production would be sometime in 2015.  That'd be about the fastest you could go.

Ray Deacon: Okay.

Steve Mueller: And Wyoming there is a gathering system there, so you'll see us later in the year drill some wells and we'll hook into that gathering system, but again it's sizing to figure out if 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 we need to and expand it.  And, again, the second half of 2015 is when you actually see the build out of the production there.

Ray Deacon: Got it. Thank you.

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

Steve Mueller: Thank you. I think back at some of the questions we've had today and there's certainly some little things here and there 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 questions sometimes 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, and 2014, September of this year, will be our tenth anniversary for production from the Fayetteville Shale.  And if you think about it only the very bravest person would have ever predicted that after 3,500 wells, 3 Tcf of gas production we'd still be driving down costs, we'd still be having questions about how many fewer days you can put into it, would be setting well production records, and we'd be improving the return on every dollar we invested.

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

And the Marcellus we're in the center of the premiere dry gas play in North America.  We continue to drive down costs.  We've got a 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 will be set 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 that development program continue into the future. Upper Marcellus we're doing our first tests there, and we're doing it actually in the center part of the upper Marcellus, in Bradford, you'll start seeing us work our way into Susquehanna in future years, and I think you're going to have upside there.  There's the Brown Dense, whatever you think about it, there are some good wells there, and hopefully we can sort that out and make it a viable play for us.  And then we have our other current exploration acreage we're 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 along.

And as I started this conference call it's all about delivering value plus for our shareholders.  We did it in 2013, and I'm confident we'll do it in 2014.  And so, with that, I'd like to end the call today.  I know a lot of you have been on -- near the end of the grind of the earnings season.  I hope you can enjoy this weekend and the next couple 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.