Coterra Energy Inc (CTRA) 2013 Q2 法說會逐字稿

Good morning and welcome to the Cabot Oil & Gas Corporation second quarter 2013 conference call. All participants will be in listen-only mode.

(Operator Instructions)

After today's presentation there will be an opportunity to ask questions.

(Operator Instructions)

Please note this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President, and CEO. Please go ahead.

Thank you, Andrew. Thank you all for joining us on this call. I have our Executive Team gathered here in the room with me. They'll be prepared to answer any questions the group might have. Before we get started let me say that the standard boilerplate language and forward-looking statements included in the press release do apply to my comments today. I plan to be brief with my comments regarding our operations discussion.

However, in light of the many questions that we received and the many media articles and speculative comments over regional basis differentials, we're going to change our typical approach to this call in order to discuss our marketing efforts in the Marcellus. We have posted a presentation titled Marcellus Marketing Supplementary Materials to our website, which can be found under the Presentation section of our website. We plan on talking about this material later in the call. And it will frame the majority of the discussion today.

However, before we jump into that discussion let me first discuss a few of the highlights of this past quarter which happens to be the best quarter in Cabot's history, both operationally and financially. For the quarter, we grew production 52% over the second quarter of last year to a record 95.2 Bcfe which equates to 1.046 Bcf per day total Company net production. Most of that growth was driven by our operations in the Marcellus where the current gross production rate is approximately 1.2 Bcf per day.

The recent jump in gross Marcellus production to over the 1.2 Bcf per day is a result of several new wells turned in line, in addition to the commissioning of the central compressor station in late June. The commissioning of central had a very minimal impact on our second quarter results, as it was not fully operational. We have witnessed a production gain of approximately 100 to 150 million per day of gross production from existing wells as the station has served to lower line pressure in the western side of our acreage position.

As I mentioned earlier, this was also Cabot's best quarter financially. We booked record net income and discretionary cash flows during the second quarter which represented an increases of 148% and 109%, respectively relative to the comparable quarter last year. As we announced in the press release last night, we have made the decision to add a sixth rig in the Marcellus which will spud its first well next month.

As a result, bringing in this sixth rig and the efficiency gains in our program, we have increased our total capital spending guidance range for the year to $1.1 billion to $1.2 billion. We also tightened the range on our 2013 production growth guidance and increased both the bottom end and top end of the range, going from 35% to 50% range to a 44% to 54% range. However, I would like to remind everyone that the addition of this sixth rig will have no impact on 2013 production as these wells would not be turned in line until next year. However, it certainly will give us a jump start for 2014.

With that I would like to move into our discussion on the marketing efforts in the Marcellus. Our marketing efforts and the regional basis differential have been the primary source of questions since our last call. I will use the supplementary slides that I have referred to and that we have posted to the website as a framework for my next comments.

On slide 1 of the posted handout is our overall strategy for marketing our Marcellus gas. Our original objective was to diversify with multiple pipeline outlets to enhance our ability to move gas out of the basin to multiple markets, while also mitigating our exposure to price volatility in regional differentials through our hedging program. To accomplish this we have pursued many different avenues including diversifying multiple pipelines, firm transportation agreements, long-term sales agreements -- that's our firm sales. Investing in new projects like the Constitution Pipeline, and opportunistically hedging a portion of our production. All of this provides us diverse opportunities to maximize the value of this tremendous resource.

Slide 2 is a map of the interstate pipeline markets where we currently deliver our gas, which is into three different pipelines. The Tennessee 300 line, the Transco line and the Millennium line. With the addition of the Constitution Pipeline in March of '15 we will be adding the Iroquois line and the Tennessee 200 line and the TransCanada Pipeline via the Iroquois line to the list as well, which would give us a total of six. At this time we certainly are fortunate to have access to three large interstate pipeline systems that all serve different market areas.

It should also be noted that all three of the pipelines we currently deliver our gas to recently completed expansion projects and publicly announced expansion plans in the future, further expanding our marketing opportunities. I would also like to point out that, as most of you are already aware, the FERC application for Constitution Pipeline was filed during the second quarter and in service is scheduled for March 31 of 2015. We continue to feel extremely confident about the project getting completed on time.

Now let's move to slide 3 which addresses our current and forecasted volumes of firm transportation contracts and long-term sales contracts. The terms of these agreements are bound by confidentiality agreements. Also note that these volumes are as of today -- will change going forward as our marketing group continues to analyze future opportunities for Cabot. As a quick refresher on this topic, contracted sales volume under our firm transportation agreements are the quantities we have reserved space for on a given interstate pipeline and allows us to ship gas without interruption. Contrary, our long-term contracted sales volumes are the volumes we have secured under long-term sales agreement, ranging from 8 to 15 years in length. Keep in mind, though, we also have shorter term deals which, when combined with these long-term arrangements, cover over 80% of our anticipated gas volumes for 2013.

For all these volumes, the gas is shipped under our -- for the long-term contracted sales volumes, the gas is shipped under our customer's firm transportation agreements, since many of our customers have owned the firm capacity on these pipelines since their inception. With regard to Cabot's firm transportation agreements, we currently hold 325 million per day of firm transportation and will add an additional 500 million per day of Cabot's firm transportation in early 2015 with the Constitution Pipeline. We also have an additional 50 million per day beginning in late '15, for a total of 875 million per day by the end of 2015. Additionally, we are in the process of negotiating select long-term firm transportation agreements that would begin late this year and would essentially increase our total firm transportation to 1 Bcf per day by the end of '15.

Just to reiterate, in addition to our short-term sales agreements, we also currently have in place fully executed long-term sales agreements for over 600 million cubic foot per day of firm sales that range from, as I mentioned, a minimum of 8 years to 15 years in duration. All of these short-term and long-term sales volumes will utilize customers' firm transportation agreements and are mutually exclusive from the firm transportation volumes mentioned previously that rely on Cabot's firm transportation agreements. These agreements significantly reduce our exposure to basis differentials. We are very excited that these long-term contracts will complement Cabot's firm transportation strategy in the years to come and we continue to look to grow these volumes over time.

We believe our marketing team with the relationships they have developed in the Appalachia region, coupled with being the first mover in the Northeast Pennsylvania area has positioned us well, as we continue to grow our production at record rates. Also, our continued commitment to growing production in the region due to the quality of our assets and our ability to recognize -- realize high rate of return even in low natural gas price environment has provided a surety of supply that many of our customers require. As a result, between our firm transportation contracts and our short-term and long-term sales contracts, the future demand requirements that we see and our relationships in the region we are very confident and comfortable about our ability to market our growing production as we move forward.

Moving to slide 4, which lays out our interstate delivery capacity, including compression and dehydration infrastructure. We are on pace to reach 2.2 Bcf per day of gross interstate delivery capacity by the end of this year, up from our previously announced 2 Bcf per day. We have increased our 2014 total capacity from 2.9 Bcf per day to 3.4 Bcf per day. By the end of 2015, we expect to reach 3.7 Bcf per day of capacity. I would like to remind everyone that these are gross capacity volumes and are not indicative of anticipated production volumes as we continue to focus our drilling program on the near term by capturing acreage, and we will certainly be drilling in areas where there is a lack of infrastructure at this current time.

Slide 5 focuses on our unhedged realized pricing for natural gas in the Marcellus. There have been a lot of questions recently relating to basis differentials in the region, and what the corresponding pricing is. So we have laid out the percentage splits of how we currently market our gas, and price our gas. As we -- as you can see the majority of our gas, about two-thirds is priced off the last day settle of NYMEX contract. The remaining production is primarily split between Columbia and Dominion indices. The Columbia indices has remained relatively strong and basically flat with NYMEX, while the Dominion has shown some weakness over the past month or so. Of the 19% we index off Dominion, approximately 70% of those volumes are hedged through the remainder of 2013. As a result, we feel we have limited exposure in the near term, if basis continues to remain soft for this index.

For first quarter one, second quarter -- for the first quarter and second quarter in aggregate, we sold our Marcellus gas approximately flat to NYMEX on an Mcf pre-hedged basis. The concern has been over recent pricing, so we have also laid out our July realizations. You will notice that July was, in fact, relatively softer, as we realized $0.15 per Mcf less than NYMEX for the month on a pre-hedged basis, which is lower than our year-to-date spread. For the remainder of the year we are forecasting a differential of approximately $0.10 to $0.15 per Mcf less than NYMEX. However, as pipeline additions come on-line in the back half of the year and winter weather materializes, these numbers could easily revert to what we have historically realized. I would also like to point out that even assuming a $0.10 to $0.15 differential at current prices, our typical Marcellus well defined as a 14 Bcf average, provides a 120% return.

Slide 6 is a recap of our current hedge position. We have about 750 million per day hedged for the remainder of the year at a floor of $3.75 and approximately 450 million a day hedged for '14 at a floor of $4.10. All align with Marcellus gas production. We will continue to opportunistically add hedges for '14. These slides should fully explain our marketing efforts and hopefully have answered all, or the majority of the questions anybody may have. We believe that our current marketing strategy, including our hedging program, has us well positioned for continued success even in the face of commodity price and basis volatility.

Now, let's move on to some of the operational highlights for the quarter. In the Marcellus we continue to see stellar well results across our acreage position. As I mentioned earlier, we are currently producing about 1.2 Bcf per day gross from only 226 horizontal wells. During the quarter we turned in line 23 wells and currently have a backlog of 37 wells, or 781 stages, either waiting on completion, completing, or waiting on pipeline.

As for individual wells, in last night's release we highlighted step-outs from our Zick area including a two-well pad to the northeast with 27 stages and had an IP of 34.8 million a day and a 30-day average of 28.1 million a day. We had another two-well pad to the north of the Zick area that was completed with 37 stages, and had an IP of 51 million per day and an average -- a 30-day average of 43.6 million a day. During the quarter we also achieved and saw our fastest well to 5 Bcf of cum production and that happened in 157 days. We also realized our fastest well to 7 Bcf of cumulative production, and that happened in less than a year at 358 days.

Our team in Pennsylvania continues to drive efficiency gains in our Marcellus program which is further evidenced by our reduction in average drilling days, and that is spud to total depth, from 16 days in '12 to 14 days in the second quarter of '13, and that's despite drilling longer laterals in the second quarter of '13. We also achieved a new record on the completion side by completing nine stages in a 24-hour period with one frac crew. They're doing a very good job. Additionally we had previously announced we ran our first ever frac pump off line gas directly from the field and continue to implement the use of CNG in our operations, which we think will further drive down drilling and completion costs as we move forward.

Now let me move to a brief comment in the South. Our operations in the Eagle Ford. We currently have one rig operating in the play. We will drop a Pearsall rig and add a rig to the Eagle Ford at the end of the this month, which is the level we expect to maintain for the remainder of the year. This second rig will be a Walking rig, and we'll focus solely on pad drilling efforts, which will consist of four- to six-wells per pad. As a reminder, we currently have 50 wells producing in our Buckhorn area and have approximately 500 net identified locations remaining in that area. Which implies over a decade worth of drilling opportunities assuming a two-rig drilling program.

As far as the Pearsall, in the third quarter we will end the drilling in the Pearsall for our 2013 time period, as planned and discussed in the previous call. We will monitor production from these wells, continue to watch industry activity for the end of the year. Brief comment in the Marmaton, that we will be slowing down our operations there, with us moving the rig to the Eagle Ford. And we will also, though, continue to maintain our acreage position up there, if it in fact, entails additional drilling or extensions.

Our team in the South region continues to focus their efforts on improving our well performance in the Eagle Ford and driving down well cost further. As the release highlighted, and it's worth repeating, our last six producing wells in the Eagle Ford have averaged a 24-hour peak rate of 900 barrels -- Boe per day. And our Eagle Ford area is about 90% oil, and that well -- those six wells had a 30-day average rate of approximately 570 Boe per day which is outperforming our average type curve.

In terms of size, we also released information on our first extended lateral well in the Eagle Ford, which had a lateral length of 8,000 feet and a 24-hour peak rate of approximately 1,130 Boe per day. Again, 90% oil. Equally impressive, however, is the fact that the well held up well and is currently producing about 1,100 barrels of oil equivalent per day after 120 days. We have also made significant steps in our operational efficiencies in the play, by reducing average drilling days in the Eagle Ford from 15 days in '12 to approximately 9 days in the second quarter in '13. We continue to work on driving well costs and anticipate the move to pad drilling will reduce Eagle Ford well costs by $500,000 to $600,000 per well.

All very positive news for Eagle Ford program as we continue to focus on accelerating value in this play going forward through operational efficiencies. However, I would like to point out that as a result of our pad drilling initiatives in the Eagle Ford and the associated increase in the spud to sale timing, because we're drilling pad wells that will sit there longer, we are slightly lowering our liquids production growth guidance for the year.

So, in summary, we continue to be very pleased with our progress, our operations progress, the growth generated from our assets, the efficiency gains, et cetera. These results delivered the best quarter in Cabot's history, and we feel like the best is yet to come. Our confidence in the future is evidenced by the announced stock split and the 100% increase in dividends. Andrew, with those brief comments, I'll be happy to take any questions.

We will now begin the question and answer session.

(Operator Instructions)

The first question comes from Brian Singer of Goldman Sachs. Please go ahead.

Thank you. Good morning.

Hi, Brian.

Appreciate the color with regards to the basis differentials and your comments and your contracts. When you put your firm transport and your long-term sales contracts together, and look out into 2015, how, if at all, would your exposure to the 65% NYMEX 30% local hubs, that we see in 2013 -- you detail on slide 5 -- change? Do you expect a meaningful shift in that split?

No.

So then I guess the question -- the follow-up question then would be what is the current market like to sign NYMEX linked agreements? Because the worry by others -- or by some would be that for incremental contracts signed that would have to be, or will stay at a discount to NYMEX.

Okay. I will pass that baton to Jeff Hutton.

Good morning, Brian. You're exactly right. In today's environment, it would not be ideal to be signing long-term agreements. We expect that environment to obviously improve. We think this is just a temporary glitch. The majority of our contracts were signed, I'm not going to disclose weeks, months, months, years, whatever -- awhile back. We've only had one small long-term contract we've entered into recently, and it was one that was negotiated for a number of months and the pricing never changed on it.

Okay, great, thanks. And then lastly, as you have seen your production grow since central compression has come on, or since the end of the quarter, can you just talk about how recent growth in the Marcellus -- how much of that has been because of favorable line pressures that have come as a result of bringing central compression on, the tying in of new wells, or just better well performance. Really trying to isolate whether you have seen an improvement in well performance or whether the recent increase -- the very recent increase in production is more to just the timing of some of these midstream and completion factors.

We have felt good about the -- what we've seen on Central. Keep in mind, Central is still in the start-up phase, in my opinion. We have -- we've done a great job, and certainly Williams has done a great job, in getting a very complicated infrastructure system up, running, and in place. But as any big operational project, we have ups and downs and starting at different times. Starting and stopping at different times. And we also have, as part of the turbine process at Central, we have three resets at Central also. So, when you look at the area of our current production, let's take the gross 1.2 Bcf, Central does not touch all of that. But when you look at the impact we think we have seen early stage in the results of just Central and not of new production, we think it has been a plus or minus 15% positive effect on existing wells.

Great. Thank you.

Thanks, Brian.

The next question comes from Ravi Sinha with Bank of America. Please go ahead.

Hi, good morning, everybody. I'm filling in for Doug Leggate. Just a quick one. Now you have added sixth rig early in the Marcellus. We want to see what does the rig actually look like in 2014 or in the outer years. And the follow-up will be where do we see the activity levels ultimately going up, given you have step-up in the cash flow.

Well, as far as the rig count is concerned we haven't given any guidance out beyond '13 at this time. We'll get more color at our next conference call in October. But our tentative plan at this stage would be to add another rig, to have seven rigs running in the field in '14. And certainly with the growth that we see out in front of us, right now, we are quite optimistic and positive about continuing our story out in front of us.

Sure. And just again in the Marcellus, how far do you think you're away from being in full pad development mode -- would you have like 500-feet spacing on all developments going forward?

We were still moving the rigs around in the field, capturing primary term acreage so we have not gotten to the stage yet where we have gone and can go into full development mode. We do anticipate in '14 to have some rig activity on pads to implement pad development, but some of our rigs also in '14 will continue to capture acreage. Full pad development will move out towards '15 when we can start talking about maybe all of our activity being on pad drilling. And as far as the spacing is concerned, we will continue to evaluate the most efficient spacing on our wells. Some of that work will be began in earnest once we are able to do some pad drilling.

Thank you. That's all. Thank you very much.

Thank you.

The next question comes from Pearce Hammond of Simmons & Company. Please go ahead.

Good morning and thanks for taking my questions.

Hi, Pearce. Dan, what are current well costs right new on the Marcellus for Cabot? And how do you see them changing when you do start drilling some of those very large pads that you were just referring to? Well, we have -- we've seen efficiencies and looking at our typical -- again, back to our typical type 14 Bcf well, we are in the, say, upper $5 millions to mid $6 million range depending on effects on roads and locations and whatnot. And we have, as you are aware, we have in our presentation -- our media presentation, we have a slide that depicts some of the savings that we think we're going to realize, comparing a 10 well pad versus a two well pad. And we think that that savings, from what we drill right now, we think that savings would be greater than $500,000 per well, once we are able to move to the pad drilling.

Great. And then one follow-up. Any updated thoughts on potential divestiture of the Marmaton?

No. We continue to have our same mentality about the Marmaton and the other areas that we are not allocating a great deal of capital to. If we find the right opportunity, and it looks like that we could find a win-win deal out there, then we would consider divesting the Marmaton, or JVing the Marmaton.

Thanks, Dan. And congrats on a great quarter.

Thanks, Pearce.

The next question comes from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.

Yes. Good morning. A couple of questions. You talked about the Central compression still being in the start-up phase. How do you see the growth from Q2 to Q3 and from Q3 to Q4 for the overall production for the Company this year?

I don't have that at my fingertips. We did revise the overall guidance from the 35% to 50% to the 44% to 54%. Marshall, I'm sorry, but I don't have just right at my fingertips the progression through third and fourth quarter. But we are -- and we do anticipate that the Central compressor, as we continue to work it, the field guys continue to manage the fueled directionality of our gas -- based on the areas of lower pressure on the gathering system -- we do expect it will be a learning curve from our guys in the field. And we do expect to see efficiency gains by virtue of this reduced line pressure.

Okay. Thank you. And when switching modes to the Eagle Ford, the longer lateral was significantly better. Do you think that you are going to plan on drilling mostly longer laterals heading forward? And what would you say your overall Eagle Ford EURs are now, based on the better results?

Well, certainly we're very pleased with the longer laterals -- or the longer lateral. By virtue of those results our guys are evaluating the layout in the field and will make an effort to drill the longer laterals than what we have been drilling in the past. I don't have and have not seen a well count yet, on how many we'll be able to get out to 7,000 or 8,000 feet, but I know that they are working on that. And with the assumption and continued good curve fits over and above our typical wells, we think we could move our EUR up in the Eagle Ford, but we're not prepared to do that at this stage.

Okay, thank you.

Thank you, Marshall.

The next question comes from Louis Baltimore of Macquarie. Please go ahead.

Thank you. In the Eagle Ford, while the first extended lateral had a very strong IP rate, after 120 days of production, it was producing essentially right in line with that 24-hour IP. Can you comment on basically what was done in this well to keep production essentially flat for an entire four months?

Well, I'll make a brief comment, then I'll throw it to Matt. Certainly pleased and knew when we look at the flow-back profile, and it had a lot of stages in there, and I don't know as it flowed back it made a difference or if we're in fractures or what, but I'll let Matt make a brief comment.

It's, as Dan said, we fracked 30 stages in that well. That well came on; it was relatively flat. Decreased slightly in its performance. I think what we -- what happened was, we continued to get contribution from additional stages, as we went on. I think we got contribution early on from the heel, and later on we started to get contribution from the other stages. And as a matter of fact, it just continues to get stronger. We've seen that well continue to improve in performance, even today. I think what's happened is we're getting additional contribution from additional stages. We also have done a few things differently in our completion techniques. And I think that has helped as well.

Okay. Great. Thank you. And then I just have one follow-up question related to the Marmaton. Initially it looked like the returns in the Marmaton were as good, if not better than, those in the Eagle Ford so I was wondering what drove the move of that one rig from the Marmaton to the Eagle Ford? Is it the increased efficiency you are seeing in the Eagle Ford now?

We have the increased efficiencies that we are realizing in the Eagle Ford. We have higher cost acreage in the Eagle Ford. We have more of a maintenance -- by primary term, maintenance issue in the Eagle Ford that we need to focus on. And that is the motivation to focus two rigs down there versus one. We are very pleased with the Marmaton, and your numbers are accurate and consistent with ours on the good returns we get from the Marmaton. We think for '13 that our primary term acreage position up in the Marmaton is in pretty good shape. All of that has influenced our decision on how to allocate our capital.

Great. That's all for me. Thank you.

Thanks.

The next question comes from Amir Arif of Stifel. Please go ahead.

Thanks. Good morning, guys. Just a couple quick questions. On the step-out well to the north -- the production per frac stage was even better. Are you moving to higher frac stages out there, or is this something specific to that one area that you needed to do?

No. We see variability in the wells. No, it was not more frac stages. We see variability in some of the wells. Not a great delta, but we do see some. In some areas we have a better -- maybe fracture system that we're connected to and can fracture into. But we have seen those type of performances, not only in the wells you are talking about, but we've seen those type of performances on a per stage basis on some of the wells also in our areas where we've done the majority of our drilling.

Okay. So there's no real meaningful change happening in the number of frac stages you are doing per well?

That is correct.

And then just a follow-up quick question on the Eagle Ford. Is there -- are you holding that well back? Is that well being choked back? Or is there surface constraints? Or is that simply what you talked about in terms of other stages slowly coming on?

No, we don't have it choked back or held back at this stage. I think along the lines what Matt indicated, it's seeing as we go and as we produce, I think, additional contributions from additional stages.

Okay. Thank you.

Thank you.

The next question comes from Bob Brackett of Bernstein Research. Please go ahead.

Hi. Question on new ventures strategy. Are you guys going to be doing along that for the next year or so?

We had talked about new ventures in the form of portfolio management. The Marmaton has been an area we have discussed, on maybe new venture opportunity. We have also looked at some of our legacy conventional assets in the Gulf Coast. And we also look at some of our East Texas properties as far as maybe an opportunity that we would create for Cabot.

Thank you.

Thank you.

The next question comes from Matt Portillo of Tudor, Pickering, and Holt. Please go ahead.

Good morning.

Good morning.

Just two quick questions from me in regards to the Eagle Ford. First, was hoping if we could get a little bit of color on the days to drill at this point?

Okay. As far as the reduction of days to drill from -- down to approximately 9 from spud to TD?

Correct.

Okay. Matt?

Sure. We've done several things. It's not just one. We've changed our bottom hole assemblies so that we don't trip as many times for our directional assemblies. We cut that trip to basically almost to one trip. That's going to be a big plus. We've pushed our motors to differentials as such that our P rates are much higher -- penetration rates are much higher than they were. Also, we've changed the way we take our directional surveys, such that we don't have to pulse the way we used to, we take with radio signals so we cut that time drastically in half. And just plus some other rig efficiencies as well.

Perfect. And then as we think about the two rigs you are running in the play today, could you give us a little bit of color on how many wells that would be per year, in terms of drilling completion? And I guess as you mentioned the 500 net wells in the play, it looks like there could be some potential for acceleration as you move out into '14 and '15 given the free cash flow generation. But just trying to get a little bit better understanding of how you think about capital allocation to the Eagle Ford.

On the rig efficiencies, we're probably looking at 20 to 25 plus or minus as far as moving forward.

If I can speak a little bit, you can look at it this way. On our pad drilling, on our first well on our rig move, it's about an 18 day -- from move to rig release to the next well. And then on every additional well, it's an additional 13 days. So roughly -- you can take that on a four well pad. I think that's roughly 57 days. And you can do the math on the six well pad. You can do the math as far as that goes on a yearly basis.

Perfect. I guess just in regards to the 500 net wells -- do you think you are optimally completing or allocating capital to the play with the two rigs running? Or is there the potential to accelerate as you move into '14 and '15 given the corporate free cash flow generation?

Certainly there's the opportunity to improve that. My reference to an extended 500 well program and how long that would last, we just referenced a two well program because that is what we are going to drill right now. But when you look at the efficiency gains that we anticipate making on pad drilling and you then roll back and once we are able to justify and realize consistent efficiency gains -- get the well cost down, show the improvement. Hopefully that we plan on seeing in the IPs and 30-day average in the IRR, then we will make a decision on how much of our free cash we will continue to allocate to the Eagle Ford. Which certainly, if Matt and his guys can do this pad drilling, they can drive the cost down, and continue to deliver and we can get the returns up into the 60%, 70%, 80% range, there's a lot of justification on allocating capital to those type of projects.

Thank you very much.

Thank you.

Next question comes from Drew Venker of Morgan Stanley. Please go ahead.

Hi. Was hoping you could talk about the Marcellus infrastructure capacity in the second half of the year and into 2014. I guess, are you -- your facilities constrained now at that 1.2 Bcf a day?

Well, I don't think we're facility constrained, per se. Where our gas is producing, though, into a high line pressure, I think we have seen that by adding additional facilities in the form of the Central compression station that by reducing those line pressures, I think -- well, we think we have seen, a plus or minus 15% improvement from the existing wells. So if, by definition, that is part of facility constraints, maybe so.

Okay. So I guess you have -- it sounds like you have a number of projects underway to help, I guess, reduce line pressure, and allow to you continue to grow throughout the year. So will you have to bring those additional projects on line to increase production in the back half of the year, or is the -- I guess is the Central station going to help you increase production in the back half?

We plan on producing production in the back half, and I'll let Jeff make some comments.

Drew, I think you hit the nail on the head. There's multiple, multiple projects that are going on. Some happened leading up to Central. Central obviously was a major milestone. A lot will happen between now and the end of the year. And these projects include additional horsepower throughout the system, bridge lines, larger diameter pipes, additional suction lines. The list goes on and on. The idea is to build a system that will -- that we can enhance our production with lower line pressure and we've got a ways to go, but these facilities are on schedule and it's very dynamic, very fluid. There's always something going on as we build this out.

Okay. And then in terms of the down spacing test you have already drilled, can you talk about the performance so far?

I'm sorry, on which one?

On the down spacing test. You guys drilled upper and lower Marcellus, I believe.

Yes. We have very few examples on the -- with the upper Marcellus, and we've been pleased with those results and what we've indicated in the past is what we see as far as the curve of it is kind of an A plus Bcf type well on the upper.

Okay. Thanks.

The next question comes from Gil Yang of DISCERN. Please go ahead.

Good morning. Following up on Brian's question from early on, you outlined nicely how the firm transportation grows but your exposure to NYMEX doesn't really change with those new contracts. But does the differential change with the increase in firm transportation versus the long-term contracts?

Okay, Gil, I think I got your question. But we'll try this. The FT, the transportation contract, as they increase. We expect to have less exposure to basis differentials. Our long-term contracts are -- we've kind of outlined here very specifically just how they play out and what we're currently experiencing on basis. Is that helpful?

I think so, but your exposure to NYMEX doesn't change, as you said. But at the same time your long-term contracts that are -- because you have more firm transportation you also have less exposure to long-term contracts overall. So I would expect the differential is improved.

In a perfect world, if differentials didn't move around like we all know they do, then the firm transportation contracts do take us places that have higher and better basis differentials in today's world.

Okay. Got you. And with the Eagle Ford well, I was just curious -- very strong well, obviously, and you commented why it's gotten good -- a good decline rate, but why -- is there something different this well that allows those extra stages to come on-line whereas other wells don't do that as consistently?

I just think it's the longer lateral. Just basically just friction. I think you tend to produce the heel stages first, and then you get contribution from the toe stages as you draw down the pressure in the heel stages.

Okay. So you're saying that dynamic is just more pronounced with the longer lateral.

It's just lift capacity.

Okay. Thank you.

Thanks, Gil.

The next question comes from Ray Deacon of Brean Capital. Please go ahead.

Hey. Dan, I was wondering if you could comment on your EURs per 1,000 foot of lateral drill. It seems like a couple of your competitors have increased their numbers. And your number is still around 2.3 Bcf. Have you seen any data that would back up an increase in that?

On which ones?

Well, basically EURs in the Marcellus per 1,000 foot of lateral drilled -- the 14 Bcf EURs.

Well, we're not -- we're looking at our curve pits, Ray, and we have a 14 Bcf type of well that we've assigned and identified as our typical well, because there's always variability in the number of stages and the lateral lengths. But on a per 1,000 foot of lateral length, we're comfortable with where we are and if down the road we can see some improvements, then we'll recognize those. But we're comfortable where we are right now and don't feel like we need to push it.

Okay. Got it. And just to follow up on your earlier comments about interstate pipeline capacity additions, do you have an estimate of how much capacity will be added in terms of total take away on big trunk lines over the next year or two in Northeast Pennsylvania?

I'll let Jeff handle that, Ray.

Ray, I've got some numbers. They're more fun facts, that a Bentek or someone would publish. But essentially northeast, there's probably 1.5 Bcf of new capacity coming on by year-end. That's a number of new projects. Again, it's very dynamic. There's just a ton of projects that are proposed, and just like any other -- about half of these projects will get built.

But we look at it two ways, because you look at pipelines that are doing expansions, like the Texas Eastern, we don't have capacity on and we don't produce into, it does regionally influence where gas flows and what happens to pricing. Then we look more specifically at the pipelines we're connected to and will be connected to and expansion projects that those pipes have. Over the next few years, it's a big number, and some of the projects won't get built, and some will get built and then expanded upon. So it's a moving target but we feel good about the expansions that have just happened in the last 12 months, for example. So the ones going forward will only enhance what our opportunities are.

Okay. Got it. Thank you.

Thanks, Ray.

the next question comes from Biju Perincheril of Jefferies. Please go ahead.

Hi, good morning. One more marketing related question. So it looks like you probably moving about 500 to maybe plus (inaudible) gas on short-term contracts. Can you talk about in the next couple of years how many of those contracts or maybe aggregate volumes that are rolling over or expiring?

No, we're not going to get that detailed. But just for example, this year we're -- probably 80% of our production is sold under contracts that are existing. That number moves around. The market is quite dynamic in how it purchases gas. There's still a lot of buyers out there for one-year deals, and a lot of buyers for April, October deals, and November, March deals, and one-month deals. It's all over the place. If it helps, we're about 80% sold for this year currently.

Okay. So then is the remaining 20% then moving on interruptible capacity, or --?

No, it's moving under firm capacity. It's just sold in the month to month market.

Got it. And then Central compressor station. Is there still a Phase 2 expansion there this year, and how do we think about -- is that at the same sort of impact to lower field-wide pressures?

There is a Phase 2 to Central. It is not this year. It's at the end 2014.

Okay. And when that comes on, it will have a similar impact? Or is that more, at that point a discharge point for constitution?

It will do both, and there will be -- there's a lot of projects between now and then, so we have no idea the effect, but we know that it -- from the hydraulics perspective from our planning teams, it's going to be very helpful.

Okay. Thanks.

The next question comes from Jack Aydin of KeyBanc.

Hi, guys. Congratulations, Dan and team.

Thanks, Jack.

Most of the questions were asked, but I got three to follow-up. A -- when did you last year reserve at Zick pad, what kind of booking did you book those wells, PDP or PUD --- on a PUD basis?

Zick was done on PDP basis for the majority of that.

Okay. So it's fair to assume that the performance of those wells that you just announced, two miles and five miles away, you were looking at the same type of reserve kind of booking?

Well, we're pleased with those wells up there.

Okay.

The early curve pit is good, and the consistency we see from how the wells come on and how they continue to fit the curve is consistent, I should say. And so we're very pleased with what we're seeing out there.

Good. Now, Dan, what do you think, what percentage of your acreage now in Susquehanna has been de-risked, in your mind?

80.

80? Okay. Next question I have for you is this -- in the Marcellus over there in Susquehanna, you've got different formation. Are you doing any different -- drilling different pilot projects to test other formation besides the Marcellus, or you don't need to do it now?

Well, we don't -- one, we don't need to do it now, and right now we are focused on the lower Marcellus at this stage. We have in the past, to gather data, we have drilled deeper than the Marcellus, and certainly we've looked at sections shallower than the Marcellus. But that's just data in the bank right now.

Okay. Thanks. Congratulations, guys.

Thanks, Jack.

The next question comes from Gordon Douthat of Wells Fargo. Please go ahead.

Good morning, guys. I know you have been asked this question before, but given kind of the dividend increase and the increase in production, going forward how do you look at balancing acceleration versus returning cash to shareholders as you look at this free cash flow profile going forward?

Gordon, this is Scott. Clearly what we have said throughout the second quarter and throughout the first half of this year when we've been asked the question, based on the parameters, the number one thing to do is to accelerate the Marcellus and we made the initial attempt to do that with the sixth rig. Clearly the horizon for the free cash flow and the level of free cash flow, while we haven't given guidance to '14, we're very comfortable with that concept for '14, and so we did take the opportunity, as we have done every time we've split the stock before, to make some move on the dividend.

Dividend -- this is not a final step with the dividend. But at the same time I'm not going to guarantee we're going move it again '14, but it is going to continue both the Marcellus and with the latest kind of results from the Eagle Ford, will become part of the operational acceleration discussion. As Dan said, depending on what kind of returns we can affect in the Eagle Ford, but dividend will still be a close kind of second to that operational discussion as we talked in the future.

Do you have a longer term growth target for the Company, or --?

In terms of dividend or just growth --

Production growth.

We're working on a model out through '17 that we'll finalize in the next month. But historically we've kind of done it one year at a time. Simply because there is a lot of noise.

Okay. Thank you.

This concludes our question and answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.

Thank you, Andrew. I appreciate everybody's diligence and the questions that were asked. Again, a lot of questions on clarity for the marketing side of it. I think the take-away is that we're very comfortable where we sit today in our marketing and its impact on realized pricing for Cabot, in spite of the volatility we see out there. And I think you have also seen some very good results in the eastern portion. Again, supporting our thesis all along, the de-risking of acreage out that way. And I think, and I was pleased to see a number of new questions regarding our Eagle Ford operation as we are now starting to show some efficiency capture and gains in that particular operation. So I'm pleased with where we are. Thanks for the interest, and we will continue to perform. Thanks.

Thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect. Have a good day.