西南能源 (SWN) 2013 Q4 法說會逐字稿

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. Stephen Mueller, the CEO of Southwestern Energy. Thank you, Mr. Mueller, you may begin.

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 www.swn.com.

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

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 achieved new levels of net income, EBITDA, cash flow, production, reserves. Well, we did that while keeping our costs low. Fayetteville records were set through increments to our completion techniques and we continue expansion into 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 you and I'm certain you'll 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 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're currently testing the first offsets to 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 by gas price in northeast Pennsylvania. Southwestern Energy strategy in both the Fayetteville Shale and the Marcellus Shale has been to purchase firm capacity in an effort to contact several liquids 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, have 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. We also know there's a high probability we'll be drilling for 10 years from now in our acreage. 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 to maximize price throughout the life of our projects is it 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. 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'd 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. 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 Bcfs a day over 2013 just to refill the storage to acceptable levels. 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. While we are, and will be, enjoying the additional cash flow from the prices we've seen so far in 2014, we have 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.

Thank you, Steve. Good morning, everyone. To further elaborate on Steve's comments, 2013 was an exceptional year for Southwestern Energy. 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. 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 costs 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 had 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. Our reserves in the area were also up 60% compared to last year. For the year, we achieved both the highest initial production rate from a well and the lowest average cost to complete that 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.

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 in 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. 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 Semans 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 have derisked 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 per day 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'll 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 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 from 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. 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. 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 of 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. 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 flow back 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. 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. 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, 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 continued to perform well 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 onto our Exploration group. At the 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's 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 expiration ideas in 2014. We'll keep you posted of our progress when the timing's 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.

Thank you, Bill. 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 and 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 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 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. We continue to monitor the gas markets. We'll be looking for opportunities to add to our hedge position in 2015 and beyond.

We are proud that we're able to keep our cash costs very low in 2013. 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 salt water 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 2012. Full cost full 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. 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 is 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. Now we'll turn it back to the operator, who will explain the procedure for asking questions.

(Operator Instructions)

Charles Meade, Johnson Rice.

If I could ask two questions on the Marcellus? The first, on the table you guys include in your press release on the 30-day rates by quarter, you had the really nice uptick in the fourth quarter with that average rate of 10. I understand that part of that's going to be the Seaman well. 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, I know the lateral length's a little bit longer, if there's perhaps a different completion design you're using there?

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. It's mostly that. We believe that we've got 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.

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. It's been pretty consistent for the last year. We're obviously still learning in the Susquehanna northeast corner area. As we learn, we may change things, but what we're really doing is just for the last six to eight months just transferring the knowledge we've learned in Bradford over to Susquehanna. As we drill it out more you may see some changes.

Got it. It does look like encouraging early indications. 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 you 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?

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

Right. So quite strong. That's the clarity I was looking for. Thank you.

Gil Yang, DISCERN.

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 your thinking at this point?

I think there's a number of dimensions in there. First of all, with lower costs and higher values realized price per gas, our inventory of drilling locations goes up and we add significantly to that. The opportunities to really bolster the IP's 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. 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. As we continue to drive costs 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 that on extended well shut-ins, or these resting that I talked about earlier, there's a IP improvement component to that. 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. You drive out even more cost out of the cost of producing a well. In turn, that can also lead to greater number of locations that remain economic.

I'll just add, 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. Going back to your inventory, I don't know how many more wells it will add but certainly is in areas where historically we had a lot lower well count and a lot lower well EURs. There will be a change, I don't know the exact answer to what the change will be.

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?

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

Okay. Along that line, just final follow up is, can you comment on the IP rate improvements that you're seeing in early 2014?

Yes. We've had a couple of wells come on recently that have been above 12 million a day, 10 and 12 million a day. 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.

Great. Thank you very much.

Scott Hanold, RBC Capital Markets.

I just wanted to delve into that question a little bit more on the PUD bookings. It went up a little bit from where we had been. When you look at some of these bigger wells that your 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 online? 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?

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

I'm sorry bout that, the Fayetteville.

Okay. I think what will happen -- you said there was a gradual step up. If you look year over year, our actual PUD bookings down a little bit. 2012 was a high-grade year ceiling. You only had 200 wells on your books. At the end of 2013, we had just under 1,100 wells on our books. Put that in perspective, at the beginning of 2012, before the gas price dropped, we had almost 1,600, 1,568 PUDs on our books. Certainly, as price works above $4, I think there's wells to come back on your books. Then, as these techniques can be applied across the field, you'll see the EURs on those individual wells raise that average also. It won't be a step-jump change. It will be as you described a gradual change, because these are gradual type things we're doing. That's probably a two- or three-year type timeframe, not a single-year timeframe.

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

Almost the same story. The only difference in Marcellus is, we're in earlier in the learning. Today we only have just over 150 well PDP wells to base any kind of decisions about. For instance, in the northeast corner of Pennsylvania, Bill said we had 40,000 acres we were very comfortable with. 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. Again, we've only had a year on the longest wells there. Those reserves will go creep up. 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 we had a good base before you saw the reserves actually start stabilizing and getting to a slow increase. When you put that in the fact that we are just now starting Sullivan, just starting Wyoming, our average may bounce around for the next year or so in the Marcellus. On each of those areas it will continue to increase.

Okay. As my follow up, on the Brown Dense, it's been a bit of a science project here for a good couple of years. 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 move on? Are we six months away from that? 12 months away from that? Can you give us a sense at a high level what the thought process is there?

You just asked one of the questions I ask every day. The hope is you have the answer tomorrow. Each new piece of information gives you some knowledge that sets up whether you can go faster or slower. We're starting to understand better where the best rock is. 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 economic and consistent. I think over the next two quarters, we will drill at least four to five wells around that Sharp area. 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? 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 at 13 wells in had 3 that were paid out, 1 that's obviously economic. Of the one company drilled, we've got another one that's economic by a third party. I don't know if it's a matter of just when, but there's certainly something there that has significant potential to it. We'll keep, as I said last conference call, we keep chipping away at it because almost no play gives you this much good indications this early. We haven't given up on it. Certainly, the three wells that 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? 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? It's not going to be as good as the central part, so we're moved back in that central part.

In the central part, since we last spoke, we've only drilled one and completed one 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.

Okay. So what I think I'm hearing, then, is you've got enough information where the reservoir is teasing you to keep going forward. What I'm hearing then is that maybe in the next 6, 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?

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

Thanks.

Drew Venker, Morgan Stanley.

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

Sure. The Milstead well's 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 the 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's 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.

Then, Steve, at what point in time -- or how long did it take for the Sharp well to reach peak production?

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

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

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 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'd normally hear excuses from various groups from. We are just early stages, and so I don't have an answer yet. I'll certainly have an answer in three months.

Okay. That's helpful. 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?

It doesn't fully reflect it, because, as you know, under SEC rules, you have to be 90% certain. Part of that certainty is, you have to have a certain length of time on wells on the 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 and where our drilling's at. Especially in Susquehanna, those better, longer wells have only been on production less than six months. So, we feel from the production that they're going to get better. They're going to be upward revisions, but you just don't physically have the data to be 90% certain so you can call an SEC reserve.

Okay. That's very helpful. Thank you.

Tim Rezvan, Sterne Agee.

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

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 fracked yet. It will be fracked in March. Then we will drill between three, I was talking about 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.

Okay. 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 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 -- do you have any kind of conviction on right now?

I'll answer two pieces to that question. Around the Sharp well, if you go from the Sharp well north and east about 3 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 a northeast southwest trend, that's the 12 plus miles I was talking about where we have seen high pressure in wells. Then, we've also seen production that would at least pay out the wells even though we had a lot of science or add issues with those wells to the pay out the total cost of those wells. 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. That's some of the things we have to learn about in some of these other wells we do around the Sharp this year. There is a core area there, could be bigger. Second half of the year has helped design how much bigger that's supposed to be.

Then, you 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 of 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. 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 State Line Trend. That well actually saw some water with completely different chlorides than anything we've seen before. 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. 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.

Okay. I appreciate the color. Thank you.

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? The Milstead well, that was only 1 mile north of the first Sharp well. Just wanted to clarify a comment you made earlier, Steve. It sounds like you did also completed the lower Brown Dense, it's just that the middle Brown Dense is only producing. Is that right?

The entire interval is fracked. We're getting most of the production out of the upper part of that interval, which is the first well when -- usually when we frac a well, we'll frac in the middle part of the well. The Sharp was the first well we'd ever fracked the very bottom part. If you remember, we had 170 barrels a day from it. This latest well fracked the entire interval. It's the first time that the middle and lower didn't contribute, -- or it didn't contribute much, so we're scratching our heads on that portion of it. That's why 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. Like I said, just be very careful trying to make an assumption or judgment off of that.

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

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

So that will come out in 2014 in terms you'll fund some new plays?

Yes.

Okay. Thank you.

Brian Singer, Goldman Sachs.

Just to follow up on the reserve bookings practices in the Marcellus, just a little bit more clarity there? I think your PUD EURs fell year on year in Bradford County and Lycoming County, but you highlighted in your comment you obviously expect ultimate EURs in Bradford and Susquehanna to be in the 10 to 16 Bcf range. Can you take us through what gets us from last year to this year? What specifically within the life of the well performance is going to get us to a higher number? I guess, as part of that, is there any discrepancy in terms of how you're thinking about things relative to your reserve engineers?

It's easy to say, we don't have any discrepancy between us and our reserve engineers. I don't know if everyone 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 it, they actually do the reserves and then we compare it back. This year was less than 5% variance in reserves. They did both the Fayetteville Shale and the Marcellus, so they actually did like 95% of our total reserves. There wasn'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 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 there, 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 shorter laterals. If you put a PUD on a 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 mix. Again, I wouldn't worry about whether it's 7.5 or 8 Bcf on average per well. You need to get it 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, whether it's frac stage or per lateral length, that is increasing, in general in all of these areas that we're drilling. 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 is going to be. That in the Marcellus, as it compares back to Bradford, as it compares from the southern side of the play, where we have year of production to the northern part of the Susquehanna where we only have a few months of production, that those wells are going to be better in the future. 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 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 to hope that well's going to do.

Okay. Thanks. 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? Then as you go forward beyond that, you would expect it to go more into development mode and the higher EUR, longer lateral, deeper areas? That's part of the reason, is just the geographic trajectory over time?

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 going to get a less EUR, just because of 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 PUDs. That's why I said earlier, I think they are all to creep up, but it's still two to three years out before you stabilize and get to the kind of numbers that Bill was talking about.

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

Our reserve engineers do reserves for a lot of companies in the northeast corner, so yes, they understand that upside. They also understand very clearly SEC rules.

Thank you.

Arun Jayaram, Credit Suisse.

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

I'll let Bill answer that.

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

To remind everyone, on 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 of 5 million a day plus. Those have only been in production a few months, so I don't know what we've got an reserves. 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. I think the worst well in there was just over 1 Bcf. When we talk about the 150,000 acres, I think, ultimately, it will 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. Where in the lower Fayetteville, your spacing maybe 400, 600 feet apart, drilling where we're at you're going to be about 1,000 feet apart in the upper.

Okay. Steve, just thinking about the way you produce 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?

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

Okay. 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. 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?

I'm feeling a little bit better than I did a few months ago, but I think this summer's going to be messy. 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 problem some. I'm not sure we are smart enough to understand which sales point's going to be the worst sales point at any point in time. There will be times during the summer I think, even with the fact that we have to get more into storage, where the sales point are going to have very low numbers. To the extent that any of us in the industry have to sell to that point, I think when we going to make those decisions about shutting in wells versus selling to those points. For us, we've got most of our gas going into Intensity gas line on 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. 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.

Thanks a lot, Steve.

Mike Kelly, Global Hunter Securities.

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

We have $150 million a day that we'll -- I don't know if we'll make it 2015. That looks like it's early 2016 or late 2015 for that Constitution line. That will go in, and that's not part of what Bill talked about as 2015 Bcf a day numbers that we had planned that later in the year. I 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 three to four years, increase is in mid Atlantic towards southeast part of the US. Any of those pipelines that are pointing in that direction are people that are talking about going that way. We're talking to them about that. One of the issues that is out there that we're debating with is that some of that's pretty expensive transportation. 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. I don't have any exact answers for you. 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. I think you'll see us try to work back in the mid Atlantic is what we're doing. What's interesting about that and I remind people all the time, as it works back toward mid Atlantic, the best gas out there suddenly becomes the Fayetteville gas, because it's the shortest gas to it. We should get a little bit of benefit on that side as well.

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

The horizontal, we've got one or two of them in the budgets later in the year. 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 verticals, so you'll see us do verticals. 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. I'll just say, stay tuned on that part.

Thank you.

Vedula Murti, CDP Capital.

Can you give us an update as to what the drilling plan is, and at least your current point of view on Paradox wells? It's hard in terms of trying to figure out a consistency there, but what's the plan for 2014 to evaluate that area?

The early plan for 2014 is watch the industry and see what they are doing. There's some wells being drilled south of our acreage block. 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. The group to the south is going after two shallower zones than the Cane Creek that we went into. 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.

Thank you.

Reham Rashid, FBR capital.

Just quickly on the -- any incremental thoughts on separating the Midstream business from the E&P business? Thank you.

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 is better than having it in some secondary part of the Company. Right now, we don't plan to do anything with the Midstream except enjoy the fruits of what we're doing and expand it.

Okay. Thank you.

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? Then one follow up on the reserve question. 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?

Let me -- I'll have Bill talk about Sullivan 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 about 15 or 16 Bcf. Most of those are in Bradford County. That's because we've been filling Bradford County for two and a half years now. When you get into Susquehanna, you've only had a year on it. While there's some very good wells at Susquehanna and we have got some wells booked above 15, you just got a very short history there. 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 15 or even 20 Bcf well, but today we can't book it at that. 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. I know there's a little bit of variance and bounce 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.

Okay.

I'll let Bill talk about Sullivan.

On Sullivan County, we're 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. These will be test wells, with some a lot of science et cetera in them. Then once we see those results come in, we'll plan some horizontal test wells to follow that. That will be spread throughout really the second and third quarters of this year. We've already drilled two, and we're evaluating the data on that.

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

Absolutely.

The Wyoming well was offsetting some of the better wells in the trend. It looked pretty good too.

Got it. 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?

Our goal for 2014 is to understand what we have in Sullivan in particular. 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 would be about the fastest you could go. In Wyoming there is a gathering system there. You'll see us later in the drill some wells that we'll hook into that gathering system. Again, it's seising to figure out if the current gathering system is big enough or if it needs to be expanded. Then, as we make that decision, we can go if it needs expanded. Again, second half of 2015 is when you'd actually see the build out of the production there.

Got it. Thank you.

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

Thank you. I think back on some of the questions we've had today, 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. That causes more questions sometimes than it might not if we hadn't given out the data. One of the things I want 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. I think we're a company that ought to be invested in.

2014, September of this year, will be our tenth anniversary for production from the Fayetteville shale. 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. We'd 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. I'm actually a lot more excited about what's going to happen in 2014. The Fayetteville Shale is continuing to improve. We discussed that. I fully expect the IPs this year are going to be better than last year in that play. We'll have days the drill go down and we'll have costs 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 costs. We've got a lot more acreage to test during the year. As we talked about it, we're going to see those bookings and all the things that go with that just better as we go through. 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 bit 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 into the future.

Upper Marcellus, we're doing our first test there. We're doing it actually in the thinner part of the upper Marcellus and Bradford. You'll start seeing us work our way in 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. Hopefully we can sort that out and make it a valuable play for us.

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. I would expect a few surprises as we go along. As I started this conference call, it's all about delivering value plus for our shareholders. We did it in 2013. I'm confident we'll do it in 2014.

With that, I'd like to end the call today. I know a lot of you, you've been near the end of the grind of the earnings seasons. I hope you can enjoy this weekend and the next couple weekends as you go through. That concludes our conference call.

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