西南能源 (SWN) 2012 Q4 法說會逐字稿

Greetings, and welcome to the Southwestern Energy fourth quarter 2012 earnings conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Steve Mueller, President and CEO. Thank you, Mr. Mueller, you may now begin.

Thank you. Good morning, and thank you for joining us. With me today are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Senior VP of Corporate Development; 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 2012, results you can find a copy of all this on our website, www.SWN.com. Also, I would 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, that are discussed in more details in the Risk Factors in the Forward-Looking Statement sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Let's begin. Our goal every year is to deliver more to our investors than our competition. Internally, we call this value plus or V plus. 2012 was another in a long string of years where we set new records, developed new efficiencies and expanded both our producing areas and our new ventures footprint. Almost every day brought new challenges, and I'm proud to state many of those challenges were converted to opportunities through the innovation and hard work of SWN staff. Our production grew by 13% as a result from our wells in the Fayetteville Shale as they improved, and our Marcellus production has begun to ramp dramatically. We also recorded our second highest cash flow ever as we have made meaningful progress in all our cash costs during 2012, and the cash flow growth from our midstream business continues its strong performance.

We began testing ideas in the Bakken in Montana and the Marmaton in Colorado, and we reached a new milestone in the Brown Dense. During the past 12 months, it has contributed to some of those daily challenges, but we are beginning to see a glimpse of how the Brown Dense might be successful, and we are in the final stages of signing up a partner to help us to reach commerciality.

All indications are that 2013 will continue the string of adding value plus. We'll drive down days and costs and ramp up production. We will also continue to add more value to new exploration ideas, new ways to approach how we work and new ways we enhance the communities where we work.

I will now turn the call over to Bill for more details on some of the value plus on operations, and then to Craig for a recap of our strong financial position.

Thank you, Steve, and good morning, everyone.

To echo Steve's comments and reflecting on the extraordinary efforts of our outstanding team of industry professionals, the Company achieved several major milestones and accomplishments during the year, which I want to share with you this morning. Among these, we expanded and advanced the Company's prospective new ventures opportunities, including acquiring new acreage and commencing testing in several new plays in addition to the nearly 495,000 net acres of undisclosed ventures in our portfolio. We grew our production to a new record of 565 Bcfe in 2012, which is up 13% compared to 2011 results.

Our growth was driven by our two core operating areas. In the Fayetteville Shale play, we grew our production by 11% to 485 Bcf versus 2011 results. From our efforts to grow our Marcellus business, we more than doubled our production from 23 Bcf in 2011 to 54 Bcf in 2012 as we expanded our development in the play to all four acreage areas. This growth more than offset the decline in our ArkLaTex production, which included a reduction due to the sale of our Overton field last year.

We continued to expand our Midstream business as we entered new producing areas. We also reduced our production expenses and general administrative expenses $0.05 per Mcf equivalent across the Company. We booked 919 Bcfe of reserves in 2012 and invested $1.9 billion. The 33% year over year decrease in natural gas price decreased our proved reserves to approximately 4 TCF equivalent from 5.9 TCF equivalent in 2011.

As gas prices rise from the $2.76 per Mcf price that was used in 2012, we know that many of these reserves that were written off at that price will naturally come back on our books over time. Our strong focus on health, safety and the environment resulted in continued improvement in HSE performance as well.

Let me speak a bit about the Fayetteville Shale. In the Fayetteville Shale, we placed 493 operated horizontal wells on production in 2012, resulting in gross operated production increasing from 1.9 Bcf of gas per day at the beginning of the year to 2.1 Bcf per day of gas at the end of year. Total prove reserves booked in the Fayetteville were approximately 3 TCF, down from 5.1 TCF at the end of 2011. Again, downward price revisions were the main driver of our decline in reserves. Our average pud well is 2.8 Bcf in 2012, compared to 2.4 Bcf in 2011.

Our operating efficiencies, driven in part by our vertical services integration, continues to improve in the Fayetteville Shale as our operated horizontal wells had an average completed well cost of $2.5 million per well, an average horizontal lateral length of 4833 feet, and an average time to drill to total depth of just 6.7 days from reentry to reentry. This compares to a well cost of $2.8 million with approximately the same lateral length that was drilled in about eight days in 2011.

Of our total 493 wells policed on production during 2012, 139 of those wells were drilled in less than five days. In total, we now have drilled 243 wells to date in five days or less. We will continue to work to drive our costs lower and expect that our vertical integration and our two newly activated SWN frac crews will make another noticeable positive impact to our well costs in 2013.

We also saw higher average production on a per well basis during 2012 as a result of the optimization efforts on our drilling portfolio. Our average initial producing rates set new records at approximately 3.6 Mcf per day compared to last year's 3.3 Mcf average rate. In the fourth quarter 2012, we set a new record as our average rate approached 4 Mcf of gas per day.

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 Bcf of natural gas per day from 1852 miles of gathering lines in the field, compared to the gathering of approximately 2.1 Bcf per day just a year ago.

Switching over to the Marcellus and our operation in Pennsylvania, we more than doubled our total proved reserves in 2012 to 816 Bcf, up from 340 Bcf booked at the end of 2011. Our average pud well is 7.6 Bcf in '12 compared to 7.5 Bcf in 2011. At December 23, we had a total of 72 wells on production, including the initial wells in our Range and Lycoming producing areas, which were first brought on production in the fourth quarter. And as I mentioned before, we are now producing from all four of our core producing areas in the Marcellus. We also have an additional 84 wells in progress in the Marcellus.

Our producing wells include 48 wells located in Bradford County, four wells in Lycoming County, and 20 in Susquehanna County. Of the 84 wells in progress at year-end, 33 were either waiting on completion or waiting to be placed to sales, including five in Bradford County, four in Lycoming County, and 24 in Susquehanna County.

Wells in our Range area where we were waiting on pipeline infrastructure are performing as expected. Our latest four wells on the Lycoming County area had IPs ranging from 9 Mcf to12 Mcf a day of gas. Our operated horizontal wells had an average completed well cost of $6.1 million per well, an average horizontal lateral length of 4070 feet and an average of 12 fracture stimulation stages in 2012, and this compares to an average completed well cost of $7 million per well, an average horizontal lateral length of 4223 feet and an average of 14 fracture stimulation stages in 2011.

In Susquehanna County, the southern portion of the Bluestone pipeline was placed in service into TGP 300 on November 28, and the northern portion of the pipeline is expected to be placed in service into the Millennium line in late first quarter. We also expect compression in our Range Trust area to be operating by mid-year, as currently we continue to produce against pipeline pressures in excess of 1000 psi. We are continuing to ramp our Marcellus business in line with available gas transportation infrastructure, and we expect our gross operated production to increase dramatically from our Marcellus properties throughout 2013 from approximately 300 Mcf per day at December 31 to over 500 Mcf per day by the end of the year.

Moving on to new ventures, at December 31, we held 3.8 million net undeveloped acres, of which 2.5 million net acres were located in New Brunswick, Canada, and the remaining approximately 1.3 million net acres were located in the US. In New Brunswick, we received two one-year extensions to our exploration license agreements in December, which extended our license to search until March 31 of 2015. We have also applied for an additional one-year extension that would extend our exploration license agreements until March 31 of 2016, if granted by the province.

In 2013, we intend to acquire approximately 130 additional miles of 2D seismic data in New Brunswick with first drilling scheduled for some time in 2014. In February, we reached a tentative agreement for a joint venture in our lower Smackover Brown Dense play in southern Arkansas and northern Louisiana that includes cash up front, as well as a three-year term carry on accelerated investment activity.

Our plan includes more active drilling program in the Brown Dense in 2013. To date in the Brown Dense, we have drilled and completed six wells, and each successive well has shown an increase in initial flow rate. Our latest well, the Doles well located in Union Parish, Louisiana had an initial flow rate of 435 barrels per day of 55 to 57 degree condensate and more than 2.5 Mcf per day of 1250 BTU gas. After flowing more than 90 days, the Doles well exhibits producing behavior similar to the BML well.

We have now spudded our seventh well, the Dean horizontal well, located in Union Parish, Louisiana. We plan to drill and complete a 3000-foot horizontal lateral with initial results expected from this well in the second quarter. This well will advance our further understanding of frac geometry and appropriate landing point, as well as cost performance. We are learning more about the play with each successive well, and we are focused on analyzing various methods to optimize our fracture stimulation with the focus on increasing reservoir contact area.

Our results along our path to commerciality continue to progress, and we continue to believe the size of the prize is significant. We remain encouraged about this play, and I look forward to updating you on our efforts to bring you this idea to commerciality in the coming months.

In our Denver-Julesberg Basin oil play in Eastern Colorado, we have leased approximately 302,000 net acres and have tested two wells in the area. Our first well encountered an oil cut of around 5%, which was lower than we expected and is currently shut-in. However, our second well, the Staner, tested seven different intervals, and we encountered an oil cut of over 40% in the vertical portion of the Marmaton. We have re-entered the Staner and are currently drilling a 3400-foot lateral in the Marmaton. We plan to complete this well during the second quarter of this year.

In 2012, we began production of our first test well targeting the Bakken formation in Sheridan County, Montana. This well achieved a peak rate of 171 barrels of oil per day and has been producing for over four and a half months. We continue to monitor the production decline in this well in addition to watching the activity around us, as there will be several more well results from other operators in the area over the next six months. We plan to spud our second well in Sheridan County in late second quarter, targeting the Three Forks objective.

Finally among the several new plays we entered in 2012, we began accumulating acreage in the Paradox Basin in Utah. We continue to lease in this area, and this is all we plan to say about this idea at this time. We remain sharply focused on adding value for each dollar we invest, and we are very excited about the opportunities that lie ahead to us in 2013 and beyond.

I will now turn it over to Craig Owen, who will discuss our financial results.

Thank you Bill, and good morning.

As Steve has mentioned, our production growth and low cost structure were strong in 2012, but did not fully overcome the impact of low natural gas prices on our earnings and cash flow. Excluding the non cash ceiling test impairments and the mark to market impact of derivative contracts, we reported net income of $485 million or $1.39 per share for the calendar year compared to $638 million or $1.82 per share in the prior year. Our cash flow from operations before changes in operating assets and liabilities was approximately $1.6 billion, the second highest level in our history, but down 9% to 2011 due to lower gas prices. Operating income for our E&P segment was $528 million excluding the non-cash items compared to $825 million in 2011.

For the year, we realized an average gas price of $3.44 per Mcf, which was down 18% from $4.19 per Mcf in 2011. We currently have 185 Bcf or approximately 29% of our 2013 projected natural gas production hedged through fixed price swaps at a weight average price of $5.06 per MMBTU. We also have added 55 Bcf of natural gas swaps in 2014 at an average price of $4.43. Our hedge position, combined with the cash flow generated by our Midstream Gathering business provides protection on approximately 50% of our total expected cash flow in 2013. 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.

We are proud that we are able to keep our cash costs very low in 2012, and our cost structure continues to be one of the lowest in our industry, with all-in cash operating costs of approximately $1.20 per Mcfe in 2012 compared to $1.24 in 2011. That includes our LOE, G&A, net interest expense and taxes.

Lease operating expenses for our E&P segment were $0.80 per Mcfe in 2012 down from $0.84 in 2011, primarily due to lower compression and salt water disposal costs associated with the Fayetteville Shale play. Our G&A expenses were $0.26 per Mcfe for the year, down from $0.27 in 2011 and were lower due to decreased personnel cost per unit of production. Taxes other than income taxes were $0.10 per Mcfe in 2012, down from $0.11 in 2011, and the full cost amortization rate in our E&P segment increased to $1.31 per Mcfe compared to $1.30 last year.

Operating income from our midstream services segment rose 19% to $294 million in 2012, and EBITDA for the segment was $339 million, also up 19%. The increase is primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale plays. We invested approximately $2.1 billion in 2012, and currently plan to invest about $2 billion in 2013. At year end 2012, our debt to total book capitalization ratio was 35%, up from 25% at the end of 2011. And that was driven by our non cash ceiling test impairments. Additionally, our total debt to trailing EBITDA ratio was about 1 times.

Our liquidity continues to be in excellent shape as we had nothing drawn on our $1.5 billion revolving credit facility at year-end 2012, and we also had $62 million of cash and restricted cash on our books. We currently expect our debt to book capitalization ratio at the end of 2013 to be approximately 34% to 36%.

In summary, while we were not able to entirely avoid the impact of the 30% drop in non-ex gas prices, we generated strong cash flow. We were able to keep our costs extremely low and exited the year in great shape with regards to our balance sheet and liquidity.

To echo Steve's comments, we look forward to 2013 and believe the combination of our Fayetteville and Marcellus assets along with new ventures ideas will provide Southwestern with the ability to add significant value for many years to come.

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

We will now be conducting the question-and-answer session. In the interest of time, and to allow as many as possible to ask questions, please limit yourself to one question and a follow-up. You may then re-enter the queue for additional questions.

(Operator Instructions)

Brian Singer, Goldman Sachs.

On the Marcellus, just looking at the chart that you had in your press release, it would appear that your 12 stage wells are trending around your 10 Bcf type curve, but I think you highlighted here that you've booked those locations at 7.6 Bcf, actually a lower number for Susquehanna County. Could you just talk to where you are and your reserve engineers are, and your level of confidence in what the ultimate EURs would be and where they are heading in the Marcellus, and how that could change, if at all, over the year?

Thank you, Brian. I'll try and tackle that a little bit. We talked -- and I'll just talk in broad terms, then we can get more specific. We talked throughout the year that, especially the Susquehanna acreage, we needed to have some production on it to even book the wells that we drilled in Susquehanna, let alone the PUD wells that were out there. We only had about a month total of production. Whether you call it engineering or non-engineering, we just didn't have that much data to be able to do much with that.

When we had that average for our various wells out there of 7.6 Bcf, certainly Susquehanna, and I can say the same thing about Lycoming with only three wells in it and a little less than two months of production, fall in that category. So, what basically happened on the PUDs that we had, we had about 73 total PUDs. 52 of those were in our Bradford County area that we have been drilling in the last couple of years, and the average on that is above the 7.6. We have wells over 15 Bcf, but that is where the high average part of it is.

There were 15 wells -- actually in Susquehanna County it was about 18 wells total that are PUDs, and there were 3 wells in the Lycoming PUDs. The range on those wells were as low as 5, and never got much above 6. So, when you put that whole mix together, is where you get to that 7.6 Bcf.

Great. Thanks. Separately, can you talk strategically with regards to any interest, if at all, in acquisitions? How many, if at all, that could be, and then where you stand on midstream monetization?

The acquisition question goes into two categories. We are not actively looking for corporate deals, buying producing assets that -- those types of things. But there is certainly that new area that maybe the new ventures group spotted that you really can't get into by leasing, and you might be able to acquire something to get into it. There is expanding potentially in areas we have, for instance, some would come up near something that we are doing in the Marcellus. So, we do have an acquisition effort, but it would be very, very targeted, and would be specifically to our talents and to us trying to expand our value and expand our footprint in certain areas.

As far as midstream monetization, I think Craig mentioned, midstream this year, along with the hedges we have, basically hedge our cash flow 50%. We like that. We like that almost any price environment; we certainly like it in the price environment we have had in 2012 and starting 2013. So, I wouldn't expect us at this point in time to do much as far as the monetization standpoint. We like where it's at, it's producing well, and it's got great economics.

Dave Kistler, Simmons & Co.

Real quickly, looking at the Brown Dense wells on the production from them the first 100 to 120 days, does that give you guys enough data to get close to deeming them commercial? And if not, what would well costs need to be versus current costs, or IPs need to be, to be able to deem that commercial at this point?

We are progressing, as we noted in my comments, we are progressing each well forward in terms of additional production coming online and productivity coming out of these wells. We are also working to drive down the cost, and we have made some very good progress on the completion and drilling side to bring those costs down. Our target range was to really try to get CapEx in these wells to about $10 million, plus or minus, and about 400 barrels a day of condensate, to achieve the level of production and the level of economics that we are after. As we look through the different wells portfolio that we have, we are making steady progress towards that.

We have another horizontal well that has just been sPUD that we've designed and are setting up to be able to try to achieve that level of cost. We still have some science in our wells that are allowing us to study this. But when you net the science out of that well program, and really look at development well program, I think that we are making some solid progress. How many more wells we'll need to be able to do that, I think is one of our uncertainties, but I can tell you that the team is pretty optimistic that we are beginning to crack the code on some of those. Fracture height continues to be the major -- an issue that we are working on, and so we are putting a lot of energy into that, at this point.

Let me just add to that. We think we can see a path that can get us to commerciality, but we are not there yet. And the reason we think we can see that path is, in the sixth well, the fractures themselves fracked easier than the previous wells that we had out there. We got all the fractures away, but as Bill said, we didn't get the fractures across the entire zone, and yet have got some decent production out of it. We are starting to be able to see a path that if we can get fractures extended across the zone, and we've got some ideas on how to do that, and it will take us several wells to figure that out, but if we can get fractures across the zone, we'll certainly have the ability to be commercial. It will take us some wells, but we are excited still about the project.

Scott Hanold, RBC Capital Markets.

If I could push a little bit more on the Smackover Brown Dense. Steve, when you step back and look at the play, do you sense there is more work to be done to bring down costs or work the geology? Where do you think you have progressed the most? And where do you see the upside optionality to get you to that economic level?

The push is everywhere. If you think about six to nine months ago, we had just run into the high pressure that we had. Since then, we have done a lot of reprocessing, and we think we can see the general outline of that on our seismic. But we need some wells to prove that we actually tied the seismic in, and that the geology looks like it is the way we think it is going to be.

On the cost side, as Bill said, we are working our way down. If you take individual intervals of the wells we have drilled to date, and say -- we do the best that we have done already, that is where you get to something just over $10 million numbers. So, we think it is able to accomplish that, but we haven't done it yet in a well, and I don't think we are going to do it in the next couple -- it will take us a little bit of time to get down there. It's going to be a combination of several things -- how we frac it, learning more about the geology, and keep driving down the costs. But those are all things we have done in the past in other plays, so it is just a matter of working our way through that.

Gil Yang, DISCERN.

Can you comment on the nature of the downward performance revisions that you talked about in the year?

We can. Most of those downward revisions, as you have seen on some of the tables, were in the Fayetteville Shale, and they are basically for the same reason. We, if you remember the last 1.5 years or so, spent a lot of time working with down-spaced wells, trying to figure out what the right spacing were. We continued to integrate that work together, and as we integrated that work together, we actually changed a little bit of the shape of the curve in the long life end of it, at the very end of it, where you are starting to see that pressure interference between wells. We have done a lot of modeling to understand that.

In layman's terms, what we basically did was take a well shape that had two components to it, that had an initial hyperbolic with some kind of terminal rate on it, and we made it into a three-segmented curve. As we did that, it changed some of our far-end reserves on our curve. On the PDP portion of that, there was about 225 Bcf that was part of that change because of that. And then on the PUD side, it gets a little bit tenuous on whether you call it price revisions or if you call it revisions that are performance revisions.

But on the PUD side, we made that revision based on what we assume the pressure gradients are going to be out long life, and then we applied the price to it. When we did that, the wells fell uneconomic, and internally we talked about -- is that a price revision or is that a performance revision? We wanted to stick with what we have done historically. Historically, we have called that a performance revision. So, there is about 135 Bcf of that, that falls in that. There's a performance revision there, but then the price drove it underneath the curve.

And I'd add -- on the first two of those categories, since they are such late life revisions, the [PB] impact is minimal on those.

Sure. I appreciate that detail. The 2.8 Vs that you booked for the PUDs, for the new PUDs, includes that new type.

Yes, every well we will book, and every well we'll do analysis on will have that kind of analysis on it. We'll keep refining that analysis, too.

Charles Meade, Johnson & Rice.

I was going to ask how you picked the Marmaton in your DJ well, but I think you guys answered that in your prepared comments when you said it had the 40% oil cut. I'm curious, can you maybe give some more detail on what kind of rate you got out of the Marmaton in that vertical completion? And if you put a frac on it? And what would be a successful rate for you in that 3,400-foot lateral?

I'll jump in and just mention a couple of broad things, and Bill can go in some more detail. On all the zones that we tested in that vertical, they were just [perf'ed] and put a little bit of acid on it, so there weren't any fracture stimulations, and we only opened those zones up for a few days. Saw oil in some of the other zones, but obviously the Marmaton was better, and Bill can go into more on the Marmaton.

When we looked in the Marmaton in the second -- in the first well, we actually fracked in or completed into two areas, and we got some [Virgil] water in that well, as well. So, the oil cut in the first well was very low, really below 20%. We anticipated 40%.

When we moved to the second well, in the Staner vertical is where we did not get into the Virgil, and managed to pick up the higher oil saturation from both the cores and from swabbing the well. Peak rate in the first well, as you asked, was 171 barrels a day, but we had 600 barrels of water. So, that well just really didn't -- it gave us some test data, but not much else.

As we go forward now, trying to complete this lateral, in reentering the Staner, I don't have off the top of my head the economic numbers for that. But certainly, we are pretty encouraged by what we saw in the vertical section.

I think a nice assumption here is -- we need about double that rate to get there. So, if we really [could get] a 40% oil cut. Now, just to the east of us, there are commercial wells, and there has been several wells that are in the progress of drilling now or have been drilled recently that have those kinds of rates on them. The highest one was 1,000 barrels a day, but there is now three or four over there with 300 to 400 barrel-a-day rates. That is the starting point for us, and we'll see where we go from there.

Abhishek Sinha, Bank of America.

Hi, I have a quick question on Fayetteville. How do you see Fayetteville wells performing from here? Do you see any room for improvement in lateral length going forward?

Going forward -- right now, in 2013, we are testing a number of -- our testing pattern is much more broad than on a comparative basis in 2012. Since we are in some relatively untested areas, the lateral length opportunities are greater, and so you could expect to see, depending on the geography and the well mix, lateral length stretching out a bit. Coming with that is the fact that we are going to be testing in some new areas that we really haven't had a lot of production history in. So, the IPs will vary, and they do vary by geography. If you recall back in the fourth quarter, we were very, very focused on a very specific set of core best wells, and as we predicted and as you saw, the IPs came up. The lateral lengths on those were up a bit, but they are limited by the units and the previous drilling. In the going-forward path, results are early in our kind of new program, but we do have and we are AFE-ing wells to be a bit longer.

That is helpful, thank you.

It is a pretty broad mix.

Bob Brackett, Bernstein Research.

Good morning. I had a question on the new venture spend for 2013. It is down to $200 million from about $300 million. Is that a shift in strategy; is that a sufficient level to find the acreage you want? Some comments?

The easy answer to that is, from a land standpoint, it is almost identical year over year in leasing. The well count -- not necessarily well count -- the well capital is down a little bit. But that is because we had assumed when we put our capital budget together that we were going to have a partner in the Brown Dense, and we'll talk more about the details later, but that is where the other capital is at.

Okay, and then in the Paradox basin, are you chasing a shale play? Or is it a more conventional play?

It is, I would call a dirty rock play. I don't know if you would call it conventional or unconventional, but it is not the classic conventional reservoirs that are out there.

And we are still leasing in that area, so we have really kind of held off on talking much more about that until we are finished.

Biju Perincheril, Jefferies & Company.

Steve, a question regarding the Fayetteville. In the past you have given some well count information at different price deck. Any update to that -- the lower well costs and some of the interference that you alluded to earlier in the call?

There is not really any update to the well count. If you think about our reserve report this year, it is about 860 wells less than it was last year, and last year had $4 price in it. So, we have always talked about the fact that you have a curve that increases from $3 to $4, and once you get up to $4, our average works at that point in time. And it really hasn't changed anything on that portion of it.

As far as the interference, I don't want to leave anyone with the impression that we are worried about the near-term interference or even worried about the interference. All we've done is now we have some longer life. Some wells up to two years length of time on them. That we have been able to pressure model large areas of the field. And as we pressure model those fields, the curve doesn't just make the nice smooth curve that you would normally think about in the overall process, and we had to break it up in a little more segments to make that model work out there. And as pressure gradients hit later in life, it has a little bit different shape to the curve, and that's what happened.

Got it. Thanks for that clarification. And in the Marcellus, can you talk about what you have in the pipeline as far as increasing your takeaway capacity there? I know in the past you have talked about [introducing an] asset that you might get to, what, 0.5[B] a day or so, but sounds like you can get there by the end of this year, if not early 2014. Can you talk about what is the capacity you have there to ramp up production even higher?

Well, today, in the Marcellus, I'll separate Lycoming out because it is under a separate arrangement. Today, we've got about 300 million a day of firm capacity that we can use, and some interruptible that we are using to move gas out. By this time next year, we will have 500 million a day of firm capacity. In fact, we have already secured it in place and ready to go.

I think I commented earlier, but -- we picked up a number -- quite a large amount of capacity in the fourth quarter. We've got some additional capacity coming on in the '14, '15 time period. And we'll be -- we are expecting, and have agreements in place, to get to 770 million a day of capacity by 2016. There is additional interruptible capacity, and our guys have been able to work that as we've ramped up. And so, for now, we've got that transportation capacity covered. And we'll drill and ramp up the asset accordingly.

David Heikkinen, Heikkinen Energy Advisors.

You guys did a great job disclosing well results by quarter as the Fayetteville moved forward. Do you have any plans, or can you provide the same format for the Marcellus and/or other areas that move into development mode?

We have been talking about that. We are not quite -- if you think about the Marcellus, the last year, all we've really had is the Bradford County. But I think you'll start seeing us do something different at the end of this quarter. Little different presentation -- I don't know exactly how it's going to look, but we'll try to get, either by area within the Marcellus, or just like we did in the Fayetteville where we say -- here's what we did each quarter, and start that same chart we had in the Fayetteville.

Cool, that will be great. Bill, you mentioned the Staner well, and I just wanted to understand -- you tested several intervals. What was the test rate for the zone that you elected to drill horizontally, or was it the one that -- did it have a higher oil cut than the 40%?

It tested 10 to 20 barrels of oil a day, and that was the 40% cut, and that was in the Marmaton part of that well. We saw some oil odor in the core, because we had that, there was some florescence, so it encouraged us enough to go in and do, and re-enter the well, which we have already started, and drill a 3,400-foot lateral to really better define that productivity in the Marmaton.

And again, I just remind you, that was -- all the tests were perforations with a little bit of acid, no frac. So, all we were trying to do is just see really -- does it have oil in it? And if you could, get a little bit of feel for what the oil cut would be.

Robert Christensen, Buckingham Research.

Yes, thank you. On this joint venture, can you articulate some of the benefits that we might anticipate? And when might a formal agreement be reached?

We are hoping within the next 60 days. But that we can talk about it in more detail. And I think the benefit is like any other joint venture, you get to help share some of the risk and you get someone to help with some of the capital part of it. So, that is the major benefits. But we'll go into more detail once we can talk about who it is and what the shape of the overall agreement is.

Would you say it would lead to a lot more wells in '13 and '14 than what you had roughly indicated in your preliminary guidance for the new ventures effort this year?

We really can't talk about that right now. As I said, we need to get that final agreement, then we can talk about it.

Scott Hanold, RBC Capital Markets.

Turning to the Fayetteville Shale, you have done a pretty good job of whittling down well costs. How low can you all go, as you walk through 2013? And when you step back and look at your well economics, relative to sort of that cost curve you talked about between $3 and $4, how much improvement could you see of that? If you can bring costs down another tier?

Well, first of all, entering into -- or ending 2012, we added our own fractionation fleet, actually two of them to do pumping services for our Fayetteville wells. So, 50% of our wells that will be fracked in this year will be fracked by our own pumping company. That brings about $150,000 per well, that is fracked by our services company, to the table. We are looking at additional time-to-drill improvement. We are already drilling faster with our drilling company than even what we finished the year with, and what we thought we were even starting this year with. You can see some improvements in time, certainly improvements in performance.

We are using 100% of our own sand for a full year now, so that brings some additional -- across all the acreage that we are drilling. Last year we had a bit of third-party sand in that mix. So, we are expecting our savings per well to come up quite a bit from last year. I don't have an exact number that we've got to put out there, but I think there is room for improvement, and I say that in the context of a great team of people who are chasing this, and that's their goal is to improve it. So, there is room for improvement, and we'll be showing you some of that examples as we go through this quarter.

That's incremental improvement from the $2.3 million you all saw in the fourth quarter. So, could you start working down to -- is $2 million per well something that theoretically you guys could get to in, say, a year or so?

Well, the market -- for the wells that are fracked by others until we expand -- until we look at whether we want to expand that, and the market rates for the outside services, that is difficult to say. Some of our contracts are tied to commodity prices, and as those commodity prices move back up, you may see some pressure on the other side. Can we reach $2 million a well? We've gotten this far; there is certainly opportunities there. Can I commit to that, at this point? Probably not.

Just to remind you, in 2013, we've guided to actually a higher number. We've actually guided to over $2.6 million. Because we are drilling some longer laterals, and we'll have higher stages of fracs, on average. This year we had about 12, I think it was, total stages, and it will go 13 to 14 next year. A year ago, I got asked that question, and my comment was -- I don't know if we can give much below a low-6 number, and we have had a couple of months here where we have been below 6, so I haven't been a really good predictor of how low we can go.

I can tell you that when you are drilling less than five days, there is no room for slip up at all. So, kind of in the back of my mind saying -- well, somewhere around five days is probably the limit. But as Bill said, they keep taking days down and keep taking costs down. So, I just look forward to next year to see if my predictions are wrong, and they have taken more out of it.

And we test quality as well, and certainly the team is producing quality wells while they are driving these days down. We are getting it on both sides.

Marshall Carver, Capital One.

Yes, on the Marcellus, it seems like your PUD bookings there are pretty conservative. If the wells end up being bigger than what you are modeling, do you start to bump against takeaway with fewer wells? What would you all do there? Would you just build the number of wells that are drilled but not on production? Would you produce restricted rates? Would you slow spending, or do you think you would be able to find some additional capacity? How would that play out over this year?

There is two pieces to that. We have kind of designed our program to follow that curve that Bill talked about earlier. Certainly you can sell into the daily market. And that all goes with what your perception of the price is, and what kind of basis issues you might have. So, that is a decision we just have to watch on a regular basis.

But your basic question was -- if the wells are much better than we have projected, what do we do? At least short term, we back off on capital and don't drill as many wells. And then, if there is a significant amount of overage on the production side of it, we go find some more capacity. And right now, the reason I say you back off in the short term, right now there is no obvious, large amount of capacity you can buy. So, you would have to build something, and that is a two-year process. So, I think, as you think about 2013, if we are better wells with just a little bit less capital in 2013, and we'll make a decision later in the year that we have to get more pipeline accelerated in 2014 and 2015.

Now that all of our areas are connected up to various pipelines, we do have some portfolio mix opportunities as well, shifting drilling from one of the areas to another. Some of our fields are dual connected to two major pipelines. So, you get more optionality in that place as well.

Okay. Thank you. That is helpful color. That is all for me.

Robert Christensen, Buckingham Research.

I think the bigger question that you have articulated on the lower Smackover Brown Dense, Steve, has been decline rates. Are they going to be exponential or hyperbolic? How many days of production do you think is needed to envision the shape of the curve, so to speak? You have a well out there, the Dean, which has been on for 110 days. We get to a point where we may look at that. What do you think?

Certainly, every day you are getting a little bit more information. We've always said that the low side of that is three to four months, and we need at least six-plus months. We are definitely on the low side of understanding that now. But we are not discouraged by what we have seen to date. I can't pound the table -- when I say not discouraged, the shape of the curve -- we are not discouraged by the shape of the curve. The real key to us is, learn a little bit more whether it takes another three months or four months to figure out the shape better. And then we know we are not contacting the entire reservoir, so how do you contact an entire reservoir?

Is there a difference, in your mind or your knowledge, of fracking a well in the Dean and getting, in the vertical sense, good frac height versus horizontal well? What might be the differences?

A lot of things could be happening. We don't know what is happening though, and that is -- this well we are drilling right now that we just moved a rig on to, is on the same pad with the Dean, we'll land at the same interval that the Dean vertical well fracked in, and we'll be able to compare the differences between there. One you frac in a vertical well, the force fields are different than a horizontal well. So, there will be differences. We just don't know what those are, and that's part of what we are going to be doing with the next well.

Coming back to the exponential hyperbolic, can we read into the Dean as we get more data over the next several months? We've got it plotted here in our offices, and not comfortable about talking about it until more data. But is that potentially the one well that could answer this question first?

I don't know. I don't know that one well answers the question. So, certainly it helps us with all of the various things we are doing to get to the answer. But I can't say that it's the key. It certainly has some different characteristics, and we need to learn about it. And really, each of the wells has some things we've done in them that is a little bit different that we are learning from. So, if I knew which was the key to unlock, we'd be there. We are just trying to figure out how to do that.

Thank you. There are no further questions at this time. I would now like to turn the floor back to management for closing comments.

Thank you. To wrap things up, I want to thank all of our employees for the truly innovative and hard work they've done to meet this year's challenges. Earlier on, I mentioned value plus. And you have heard a lot about value plus from both Bill and Craig, and then our discussion on the Q&A today. One of the things I want to remind you is that the portfolio of projects give you value. It is our employees that really give the plus part of that. And that plus part is both for our shareholders or the environment and the communities we work in.

As we look out into 2013, there is going to be a lot of other things that is going to happen this year, and for the first time in many years, we've got another project, the Marcellus, which will share the spotlight with the Fayetteville Shale. And it is not because the Fayetteville Shale's either getting old or slowing down, it is simply that we have been able to add value plus by adding the Marcellus into the system. We'll continue to march forward trying to make the Brown Dense commercial, but that is only a small part of our exploration program. Again, there is much more.

2013 will be the first year of many, many years to come where we will be testing about 1 million acres per year of new ideas as we go through. There is Colorado, Montana, we mentioned the Paradox basin, all part of that 490,000 other acres. And then, don't forget New Brunswick, where we have 2.5 million acres; we'll shoot seismic this year and look forward to drill something in 2014.

Finally, from the value plus standpoint, I want to remind everyone that we are going to continue doing things right, and that means being safe, reduce our operational footprint, and reduce the water we use, and keep the air we breathe clean. With that, I thank you for listening today; that concludes our teleconference.

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