Jeff Sherrick - Southwestern Energy, Senior VP of Corporate Development

Brad Sylvester - Southwestern Energy, VP of Investor Relations

Analysts

Brian Singer - Goldman Sachs, Analyst

Dave Kistler  - Simmons and Company, International, Analyst

Scott Hanold - RBC Capital Markets, Analyst

Gil Yang - Bank of America Merrill Lynch, Analyst

Charles Meade - Johnson and Rice Company, Analyst

Abhishek Sinha - Bank of America Merrill Lynch, Analyst

Bob Brackett - Bernstein Investment Research & Management, Analyst

Biju Perincheril - Jefferies & Company, Inc., Research Division

David Heikkinen  - Heikkinen Energy Advisors, Analyst

Robert Christensen  - Buckingham Research, Analyst

Marshall Carver  - Capital One, Analyst

Presentation

Operator: Greetings, and welcome to the Southwestern Energy Fourth Quarter 2012 Earnings Conference Call. (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.

Steve Mueller, President and Chief Executive Officer

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've 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 of 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 and are discussed in more detail in the Risk Factors and 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+, or V+. 2012 was another in a long string of years where we've 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 say many of those challenges were converted to opportunities due to 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 lowering 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're beginning to see a glimpse of how the Brown Dense might be successful and we're 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+, will drive down days and costs, and ramp up production. But 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+ in our operations, and then to Craig for a recap of our strong financial position.

Bill Way, Executive Vice President and Chief Operating Officer

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 in advance 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 Bcf equivalent 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 Ark-La-Tex 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 by $0.05 per Mcf equivalent across the Company.  We booked 919 Bcf equivalent 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 are 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. 

Fayetteville Shale Play

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 the year. Total proved

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 4,833 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 placed 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 million cubic feet per day, compared to last year's 3.3 million cubic feet average rate.

In the fourth quarter of 2012, we set a new record as our average rate approached 4 million cubic feet 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 billion cubic feet of natural gas per day from 1,852 miles of gathering lines in the field, compared to the gathering of approximately 2.1 Bcf per day just a year ago.

Marcellus Shale

Switching over to the Marcellus, in 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 2012, compared to 7.5 Bcf in 2011. And at December 31, 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've 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 million to 12 million cubic feet 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 4,070 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 42.23 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 1,000 PSI.

We're 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 million cubic feet per day at December 31 to over 500 million cubic feet per day by the end of the year.

New Ventures

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 U.S. 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, 2015. We've also applied for an additional one-year extension that would extend our exploration license agreements until March 31, 2016, if granted by the province.

In 2013, we intend to acquire approximately 130 additional miles of 2-D 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 upfront, 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 rates. Our latest well, the Doles well, located in Union Parish, Louisiana, had an initial flow rate of 435 barrels per day, a 55 degree to 57 degree condensate, and more than 2.5 million cubic feet per day of 1,250 Btu gas. After flowing more than 90 days, the Doles well exhibits producing behavior similar to the BML well. 

We've now spudded our seventh well, the Dean Horizontal well, located in Union Parish, Louisiana. We plan to drill and complete a 3,000-foot horizontal lateral with initial results expected from this well in the second quarter. This well will advance our further understanding of frac geometry, an 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 a 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 this idea to commerciality in the coming months.

In our Denver Julesburg Basin oil play in Eastern Colorado, we've 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've reentered the Staner and are currently drilling a 3,400-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 4.5

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 for us in 2013 and beyond.

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

Craig Owen, Senior Vice President and Chief Financial Officer

 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 the 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 weighted 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 we'll be looking for opportunities to add to our hedge position.

We are proud that we're 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 the lower compression in 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 a 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 pool 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 was 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 is about 1x. 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 NYMEX 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.

Questions and Answers

Operator: Thank you. (Operator Instructions) Thank you. Our first question comes from the line of Brian Singer of Goldman Sachs.  Please proceed with your question.

Brian Singer: Thank you. Good morning.

Steve Mueller: Good morning.

Brian Singer: On the Marcellus, 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 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 in your level of confidence in what the ultimate EURs would be and where they're heading in the Marcellus, and how that could change, if at all, over the year?

Steve Mueller: 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 at our--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.  So whether you call it engineering or non-engineering, we just didn't have much data to be able to do much with that. And so, when we add 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've been drilling in the last couple of years. And the average on that is above the 7.6 Bcf.  We have wells that are over 15 Bcf, but that's where the high average part of it is.

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

Brian Singer: Great. Thanks. And then, 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?

Steve Mueller: The acquisition question goes into two categories. We're not actively looking for corporate deals, buying and producing assets, and those types of things. But there's 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, if something would come up near something we're doing in the Marcellus. So we do have an acquisition effort, but it would be 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 the 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've had in 2012 and starting in 2013.  So I wouldn't expect us at this point in time to do much as far as a monetization standpoint. We like it where it's at.  It's producing well and it's got great economics.

Operator: Thank you. Our next question comes from the line of Dave Kistler, Simmons and Company.  Please proceed with your question.

Dave Kistler: Morning, guys.

Steve Mueller: Morning.

Dave Kistler: Real quickly looking at the Brown Dense wells on the production from them in the first 100 days 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?

Bill Way:  Well, we are progressing, as we noted in our--my comments. We're progressing each well forward in terms of additional production coming online and productivity coming out of these wells.  We're also working  toward--to drive down the cost. And we've 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 then the level of economics that we're after. As we look through the different wells--portfolio that we have, we're 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 those--that well program and really look at development well program, I think that we're 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're beginning to crack the code on some of those.

Fracture height continues to be the major--or an issue that we're working on, and so we're putting a lot of energy into that at this point.

Steve Mueller: And let me just add to that. We think we can see a path that can get us to commerciality, but we're not there yet. And the reason we think we can see that path is in the sixth well the fractures themselves frac 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.  So we're 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 that we'll certainly have the ability to be commercial.  So it will take us some wells, but we're excited still about the project.

Operator: Thank you.  Our next question is coming from the line of Scott Hanold of RBC Capital Markets.  Please proceed with your question.

Scott Hanold: Yes, thanks. Good morning. 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's more work to be done to bring down cost or the geology? So where do you think you've progressed the most and where do you see the upside optionality to get to that economic level?

Steve Mueller: Oh, it's--the push is everywhere. If you think about six months to nine months ago, we had just run into the high pressure that we had. Since then, we've 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's the way we think it's going to be. And then, on the cost side, as Bill said, we're working our way down. If you take individual intervals of the wells we've drilled to date and say we do the best that we've done already, that's where you get to his something just over $10 million number. So we think it's accomplished--able to accomplish that. We haven't done it yet in a well and I don't think we're going to do it in the next couple. It will take us a little bit of time to get down there. So it's going to be a combination of several things - how we frac it, learning more about the geology, and driving down the costs. But those are all things we've done in the past in those plays.  So it's just a matter of working our way through that. 

Operator: Thank you. Our next question is from the line of Gil Yang of Bank of America Merrill Lynch. Please proceed with your question.

Gil Yang: Good morning, everyone. Hi, Steve. 

Steve Mueller: How's it going, Gil?

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

Steve Mueller: We can. Most of those downward revisions, as you've seen some of the tables, were in the Fayetteville Shale and they're basically for the same reason. We, if you remember, the last year and a half 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're starting to see a pressure interference between wells. And we've 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 initially hyperbolic with some kind of terminal rate on it, and we made it into a three segmented curve.  And 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 now, 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 to that based on what we assumed the pressure gradients are going to be out long life, and then we applied the price to it. And when we did that, the wells fell uneconomic. And we had--internally, we talked about is that a price revision or is that a performance revision? We wanted to stick with what we've done historically.  Historically, we've called that a performance revision. So there's about 135 Bcf of that that falls in that. There's performance revision there, but then the price drove it underneath the curve.

Bill Way: And then, I'd add on the first two of those categories, that since they are such late life revisions, the PV impact is minimal on those.

Gil Yang: Sure. I appreciate that detail. The 2.8 B that you booked for the PUDs, then--for the new PUDs includes that new type--

Bill Way: --Yes. Every well we'll book and every well we'll do analysis on will have that kind of analysis on it and we'll keep refining that analysis, too.

Operator: Thank you. Our next question comes from the line of Charles Meade of Johnson Rice. Please proceed with your question.

Charles Meade: Good morning, gentlemen. Thanks for taking my question. Actually, in--I was going to ask how you picked that--the Marmaton in your DJ well, but I think you guys answered that in your prepared comments when you said they'd had the 40% oil cut. But 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?

Steve Mueller: I'll jump in and just mention a couple of broad things, and Bill can go into some more detail. On all of the zones that we tested in that vertical, they were just perked and put a little bit of acid of 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 is a better--and Bill can go into more on the Marmaton.

Bill Way: When we looked in the Marmaton in the second--in the first well, we actually frac'd--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're pretty encouraged by what we saw in the vertical section.

Steve Mueller: I think a nice assumption here is we need about double that rate--

Bill Way: Right.

Steve Mueller: --to get there. And that--so we really could get a 40% oil cut.  Now just to the east of us, there are commercial wells and there's 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's now three or four over there with 300 to 400 barrel a day rates.  And so, that's the starting point for us, and we can still go from there.

Operator: Thank you. The next question comes from the line of Abhishek Sinha of Bank of America Merrill Lynch.  Please proceed with your question.

Abhishek Sinha: Yes, hi. I just have a quick question on Fayetteville.  I was wondering how is the Fayetteville well performing from here? Do you see any room for improving lateral lengths going forward?

Steve Mueller: Going forward--right now in 2013 we're testing a number of--our testing pattern is much more broad than--on a comparative basis in 2012.  So we have the--since we are in some relatively untested areas, the lateral length opportunities are greater. And so, we--you could expect to see--depending on the geography and the well mix, lateral lengths stretching out a bit. Coming with that is some--the fact that we're going to be testing in some new areas that we really haven't had a lot of production history in.  And so, the IPs will vary and they do vary by geography. So if you recall back in the fourth quarter we were very focused on a very specific set of core best wells and as you--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're AFE'ing wells to be a bit longer.

Abhishek Sinha: Okay, that's helpful. Thank you.

Steve Mueller: It's a pretty broad mix.

Operator: Our next question comes from the line of Bob Brackett of Bernstein Research. Please proceed with your question.

Bob Brackett: Good morning. I had a question on the new venture spend for 2013. It's 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?

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

Bob Brackett: Okay. And then, in the Paradox Basin, are you chasing a shale play or is it a more conventional play?

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

Bill Way: And we're still leasing in that area, so we've really kind of held off on talking much more about that until we're finished.

Operator: Thank you. Our next question is from the line of Biju Perincheril of Jefferies and Company.  Please proceed with your question.

Biju Perincheril: Hi. Good morning. Steve, a question regarding the Fayetteville. In the past you've given some well count information at different price sets. Any update to that, the lower well cost, and some of that interference that you alluded to earlier in the call?

Steve Mueller: There's not really any update to the well count. If you think about our reserve report this year, it's about 860 wells less than it was last year, and last year it had a $4 price in it. So we've always talked about the fact that you've got a curve that increases from $3 to $4. Once you get it 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're worried about the near term interference or even worried about the interference. All we've done is now we've got some longer life. 

We've got some of our wells up to two years length of time on them that we've been able to pressure model large areas of the field. And as we pressure model the fields, the curve doesn't just make the nice smooth curve that you 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 so, as the pressure gradients hit later in the life, it has a little bit different shape to the curve, and that's what happened.

Biju Perincheril: 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've talked about this is an asset that you might get to about .5 B a day or so. And it sounds like you can get there by the end of this year, if not early '14.  But can you talk about what is the capacity that you have there to ramp up production even higher?

Steve Mueller: Well, today in the Marcellus, we've--I'll separate Lycoming out because it's kind of 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. And by this time next year, we will have 500 million a day of firm capacity--in fact we've 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're 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.

Operator: Thank you.

Steve Mueller: But we'll ramp--then we'll drill and ramp up the asset accordingly. 

Operator: Thank you. Our next question is coming from the line of David Heikkinen of Heikkinen Energy Advisors. Please go ahead with your question.

David Heikkinen: Good morning, guys. You guys did a great job disclosing all the results by quarter as the Fayetteville moves 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?

Steve Mueller: We've been talking about that. We're not quite--the thing with the Marcellus the last year all we really had is Bradford County. But I think you'll start seeing us do something different at the end of this quarter with a 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.

David Heikkinen: Okay, cool. That will be great. And then, 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 had the high--did have a higher oil cut than the 40%?

Bill Way: Well, in the--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 later in the core, because we had that--there's some fluorescence. So it encouraged us enough to go in and do--and reenter the well, which we've already started, and drill a 3,400 foot lateral to really better define that productivity in the Marmaton.

Steve Mueller: And again, I'll just remind you that was a--all the tests were perforation 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 new oil cut would be.

Operator: Thank you. The next question is coming from the line of Robert Christensen of Buckingham Research. Please proceed with your question.

Robert Christensen: 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?

Steve Mueller: We're 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's 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.

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

Steve Mueller: We really can't talk about that right now. As I said, we're just--we need to get that final agreement, then we can talk about it.

Operator: Thank you. Our next question is a follow up from the line of Scott Hanold of RBC Capital Markets.  Please go ahead with your question.

Scott Hanold: Yes, thanks. Turning to Fayetteville Shale, you've 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 that if you can bring costs down another tier?

Steve Mueller: 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 half of our wells that will be frac'd in the coming--in this year will be frac'd by our own pumping company. That brings about $150,000 per well that is frac'd by our services company to the table.

We're looking at additional time to drill improvement.  We're 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. So you'll see some--you can see some improvements in time, certainly improvements in performance. We're using 100% of our own sand for a full year now, so that brings some additional across all of the acreage that we're drilling.  Last year, we had a bit of third party sand in that mix. And so, we're 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's room for improvement and we'll be showing you some of the examples as we go through this quarter.

Scott Hanold: Yes. And so, is that incremental improvement from the $2.3 million you all saw in the first fourth quarter? I mean, could you start working down to--I mean, is $2 million per well something that theoretically you guys could get to in say a year or so?

Steve Mueller: Well, the market, for the wells that are frac'd by others until we expand--until we look at whether we want to expand that, and the market rates for the outside services, that's difficult to say. I think 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. So can we reach $2 million a well? We've gotten this far.  There's certainly opportunities there. Can I commit to that at this point?  Probably not.

Steve Mueller: And I think 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. It'll go 13 and 14 next year. A year ago I got asked that question, and my comment was I don't know if we can get much below a low six number. And we've got a couple of months here where we were below six, so I haven't been a really good predictor of how low we can go. I can tell you that when you're drilling less than five days, there is no room for slip-up at all. So I kind of in the back of my mind say, 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've taken more out of it.

Bill Way: And we test quality as well, and certainly the team is producing quality wells while they're driving these days down. So we're getting in on both sides.

Operator: Thank you. Our next question is from the line of Marshall Carver of Capital One. Please proceed with your question.

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

Steve Mueller: There's two pieces to that. We've 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's 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's a significant amount of overage on the production side of it, we go find some more capacity. And right now the reason you back off in the short term, right now there's no obvious large amount of capacity you can buy, so you'd have to build something. And that's a two year process. So I think as you think about 2013, if we're better wells, we'll just do a little bit less capital in 2013, and we'll make a decision later in the year that we have to get more pipeline and accelerate in 2014, 2015.

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

Marshall Carver: Okay. Thank you. That's helpful color. That's all for me.

Operator: Our next question is from the line of Robert Christensen, Buckingham Research. Please go ahead with your question.

Robert Christensen: I think the bigger question that you've articulated on the Lower Smackover Brown Dense,  Steve, has been decline rates. Are they going to be exponential or hyperbolic? And 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, and we get to a point where we may look at that.  What do you think?

Steve Mueller: Certainly, every day you're 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, so we're definitely on the low side of understanding that now. But we're not discouraged by what we've seen to date. I can't pound the table with--when I say not discouraged--the shape of the curve--we're not discouraged by the shape of the curve. The real key to us is learn a little bit more as--whether it takes another three months or four months to figure out the shape better, and then we know we're not contacting the entire reservoir, so how do you contact that entire reservoir?

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

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

Robert Christensen: 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?

Steve Mueller: 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're 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's a little bit different that we're learning from. So if I knew which was the key was to unlock, we'd be there. So we're just trying to figure out how to do that.

Robert Christensen: Thank you.

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

Steve Mueller: 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+, and you've heard a lot about Value+ from both Bill and Craig, and in our discussion with Q and A today. One of the things I want to remind you is that the portfolio projects give you value. It's 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's 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's not because the Fayetteville Shale's getting old or slowing down.  It's simply that we've 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's only a small part of our exploration program. Again, there's much more. 2013 will be the first year of many years to come where we'll be testing about 1 million acres per year of new ideas as we go through. There's Colorado, Montana--we mentioned the Paradox Basin, all part of the 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.

And then finally, from the Value+ standpoint, I want to remind everyone that we're 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. And with that, I thank you for listening today. That concludes our teleconference.

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

Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three and twelve months ended December 31, 2012 and December 31, 2011. Non-GAAP financial measures should not be considered in isolation or as a substitute for the company's reported results prepared in accordance with GAAP.