Morning, and welcome to the Cabot Oil and Gas Corporation Second Quarter 2013 Conference Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Dan Finches, Chairman, President and CEO.
Please go ahead.
Thank you, Andrew, and thank you all for joining us on this call. I have our executive team gathered here in the room with me and they'll be prepared to answer any questions the group might have. Before we get started, let me say that the standard borrower plate 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 Q2 of last year to a record 95.2 Bcfe, which equates to 1.046 Bcf per day of 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 2nd quarter results as it was not fully operational. We have witnessed a production gain of approximately $100,000,000 to $150,000,000 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 2nd 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 6th rig in the Marcellus, which will spud its first well next month. As a result of bringing in this 6th rig and the efficiency gains in our program, we have increased our total capital spending guidance range for the year to 1.1 $1,000,000,000 to $1,200,000,000 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 the 6th 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 20 14. With that, I would like to move into 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've referred to and that we've 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 3 different pipelines, the Tennessee 300 line, the Transco line and the Millennium line. With the addition of the Constitution pipeline in March of 2015, we will be adding the Iroquois line, the Tennessee 200 line and the Trans Canada pipeline via the Iroquois line to the list as well, which would give us a total of 6. At this time, we certainly are fortunate to have access to 3 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 Q2 and in service is scheduled for March 31, 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 our 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 customers' 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 325,000,000 dollars per day of firm transportation and we'll add an additional $500,000,000 per day of Cabot's firm transportation in early 2015 with the Constitution pipeline.
We also have an additional $50,000,000 per day beginning in late 2015 for a total of $875,000,000 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 2015. 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 600,000,000 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 1st 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 2 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 Q1, Q2 for the Q1 and Q2 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 hedge 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 online 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 point dollars 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 $750,000,000 per day hedged for the remainder of the year at a floor of $375,000,000 and approximately $450,000,000 a day hedged for $14,000,000 at a floor of 4 point $1.0 all aligned 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 2 well pad to the Northeast with 27 stages and had an IP of 34,800,000 a day and a 30 day average of 28,100,000 a day. We had another 2 well pad to the north of the Zick area that was completed with 37 stages and had an IP of $51,000,000 per day and an average of 30 day average of $43,600,000 a day. During the quarter, we also achieved and saw our fastest well to 5 Bcf of and that happened in less than a year at 3 58 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 'twelve to 14 days in the Q2 of 'thirteen and that's despite drilling longer laterals in the second quarter of 'thirteen. We also achieved a new record on the completion side by completing 9 stages in a 24 hour period with 1 frac crew. They're doing a very good job. Additionally, we have previously announced we ran our first ever frac pump offline gas directly from the field and continue 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 and our operations in the Eagle Ford.
We currently have 1 rig operating in the play. We will drop a Pearsall rig and add a rig to the Eagle Ford at the end of this month, which is the level we expect to maintain for the remainder of the year. The second rig will be a walking rig and we'll focus solely on pad drilling efforts, which will consist of 4 to 6 wells per pad. As a reminder, we currently have 50 wells producing in our Buck Horn area and have approximately 500 net identified locations remaining in that area, which implies over a decade worth of drilling opportunities assuming a 2 rig drilling program. As far as the Pearsall in the Q3, we will end the drilling at in the Pearsall for our 2013 time period.
As planned and discussed in the previous call, we will monitor the production from these wells, continue to watch industry activity for the end of the year. A brief comment in the Marminton that we will be slowing down our operations there with us moving the rig to the Eagle Ford and we will also go 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 6 producing wells in the Eagle Ford had 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 6 wells had a 30 day average rate of approximately 5.70 BOE per day, which is outperforming our average type curve. In terms of science, 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 11.30 BOE per day, again 90% oil.
Equally impressive, however, is the fact that the well held up well and is currently producing about 1100 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 'twelve to approximately 9 days in the Q2 in 'thirteen. We continue to work on driving well cost and anticipate the move to pad drilling will reduce Eagle Ford well cost by $500,000 to $600,000 per well. All very positive news for our 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 sell timing because we're drilling pad wells, I'll 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, etcetera. 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. The first question comes from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Hey, Brian.
Appreciate the color with regards to the basis differentials in your comments and in 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. And 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 the worry by some would be that for incremental contract signs, 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, a while 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. And then lastly, as you've 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? And really trying to isolate whether you've seen an improvement in well performance or whether the recent increase in
good about the what we've seen on Central. Keep in mind, Central is still in the startup 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 3 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 +orminus15% positive effect on existing wells.
Great. Thank you.
Thanks, Brian.
The next question comes from Avi Sinha of Bank of America. Please go ahead.
Yes. Hi, good morning, everybody. I'm filling in for Doug Leggate. Just wanted a quick one. So now you have added 6th rig early on in the Marcellus.
So we want to see like what stacked rig activity looks like in 2014 or in the outer years? And the follow-up will be like where do we see the activity levels ultimately going up given you have stepped 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 7 rigs running in the field in 2014. 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 you think you're away from being in full pad development mode? And so and would you have like 500 feet spacing and all of the wells going forward?
Well, 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 2014 to have some rig activity on pads to implement pad development, but some of our rigs also in 2014 will continue to capture acreage. Full pad development will move out towards 2015 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 I have. Thank you very much.
Thank you.
The next question comes from Pierce Hammond of Simmons and Company. Please go ahead. Good morning and thanks for taking my questions.
Hey, Pierce.
Dan, what are current well costs right now 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're in the say upper $5,000,000 to mid $6,000,000 range depending on effects on roads and locations and whatnot. And we have as you're 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 2 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 pad drilling.
Great. And then one follow-up, any updated thoughts on the potential divestiture of the Marmaton?
No. We continue to have our same mentality about the Marminton and the other areas that we are not allocating a great deal of capital to. And if we find the right opportunity and it looks like we could find a win win deal out there, then we would consider divesting the Marmaton or japing the Marmaton.
Thanks, Dan, and congrats on a great quarter.
Thanks, Piers.
The next question comes from Marshall Carver of Heikkinen Energy Advisors. Please go ahead.
Yes. Good morning. Couple of questions. You talked about the central compression still being in the startup 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 3rd Q4. But we are and we do anticipate that the central compressor as we continue to work it, the field guys continue to manage the field directionality of our gas based on the areas of lower pressure on the gathering system, We do expect there 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 one switching modes to the Eagle Ford. The longer lateral was significantly better. Do you think you're 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 and are the longer lateral. And by virtue of those results, our guys are evaluating the layout in the field and we'll make an effort to drill the longer how many we'll be able to get out to 7000 or 8000 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.
Yes. Thank you. In 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 4 months?
Well, I'll make a brief comment, then I'll throw it to Matt. Certainly, pleased and new when we look at the flowback profile and it had a lot of stages in there. And I don't know as it flowed back if it made a difference or if we're in fractures or what, but I'll let Matt make a brief comment.
It's a as Dan said, we frac 30 stages in that well. And if that well came on, it was relatively flat, decreased slightly in its performance. And I think what happened was we continued to get contribution from additional stages as we went on. I think we got contribution early on from the Hill. 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 we'll continue to improve in performance even today. So 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's helped as well.
Okay, great. Thank you. And then I just have one follow-up question related to the Marmerton. Initially, it looked like the returns in the Marmerton were as good, if not better than those in the Eagle Ford. And so I was wondering what drove the move of that one rig from the Marmerton to the Eagle Ford.
Is it the increased efficiencies you're seeing in the Eagle Ford now?
Well, 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 primary term maintenance issue in the Eagle Ford that we need to focus on. And then that is the motivation to focus 2 rigs down there versus 1. We are very pleased with the Marminton and your numbers are accurate and consistent with ours on the good returns we get from the Marminton, we think for 2013 that our primary term acreage position up in the Marminton is in pretty good shape.
So that all of that has influenced our decision on how to allocate our capital.
Great. And that's all for me. Thank you.
Thanks.
The next question comes from Mir Harif of Stifel. Please go ahead.
Thanks. Good morning, guys. Good morning. Just a couple of 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 just something specific to that one area that you needed to do?
No.
We see variability in the wells and 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're talking about, but we've seen those type of performances on a per stage basis on some of the wells also in our areas we've done majority of our drilling.
Okay. So there's no real meaningful change happening in the number of frac stages you do for a well?
That's correct.
For a program? Okay. Correct. And then just a follow-up quick question on the Eagle Ford. 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 of 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 venture strategy. Are you guys going to be doing anything along that for the next year or so?
Well, we have talked about new ventures in the form of portfolio management And the Marminton has been an area that we've 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 for me in regards to the Eagle Ford. First, I
was just hoping if we could get a little bit of
color on the days to drill at this point?
Okay. As far as the reduction in 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 time basically almost to one trip. That's been a big plus. We've pushed our motors to differentials such that where our P rates are much higher, penetration rates are much higher way we used to. We take with radio signals, so we cut that time 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 2 rigs you're 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, kind of it looks like there could be some potential for acceleration as you move out into 2014 and 2015 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.
All right. On the rig efficiencies, we're probably looking at 20 to 25 plus or minus as far as moving forward?
Yes. I can speak a little bit. Just you can look at it this way. We 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 additional 13 days.
So roughly, you can take that on a 4 well pad. I think that's roughly 57 days and you can do the math on the 6 well pad. So you can do the math as far as that goes on a yearly basis.
Perfect. And I guess just in regards to the 500 net wells, do you think kind of optimally completing or allocating capital to the play with the 2 rigs running? Or is there the potential to accelerate as you move into 2014 and 2015 given the corporate free cash flow generation?
Certainly, there is the opportunity to improve that. And my reference to an extended 500 well program and how long that would last, we just referenced a 2 well program because that's what we're 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.
The next question comes from Drew Venker of Morgan Stanley. Please go ahead.
I 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 facility is 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 you to continue to grow throughout the year. So we have to bring those additional projects online 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?
Rodney McMullen:] 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, and 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, I mean 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. So there's always something going on as we build this
out.
Okay. And then in terms of the downspacing tests you've 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. Well, 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 is kind of an A plus Bcf type well on the upper.
Okay. Thanks.
The next question comes from Gil Yang of Dacern. Please go ahead.
Good morning. Following up on Brian's question from early on, you outlined nicely how the firm transportation grows and 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 phases excuse me, the Feet, the transportation contracts, as they increase, we expect to have less exposure to basis differentials. Our long term contracts are I mean, 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 I yes, so your exposure to NYMEX doesn't change as you said. But at the same time, your long term contracts that are but because you're more further in transportation, you also have less exposure to long term contracts overall. So I would expect that the differentials improve.
Well, if 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 then with the Eagle Ford well, I was just curious, very strong well obviously and you commented why it's gotten good decline rate. But why is there something different about this well that allows those extra stages to come online, whereas other wells don't do that as consistently?
I just think it's a longer lateral. I mean, just basically just friction. I think you tend to produce the hill 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 just saying that that dynamic is just more pronounced with a longer lateral? It's just lift capacity.
Yes. Okay. All right. Thank you.
Thanks, Gail.
The next question comes from Ray Deacon of Breen Capital. Please go ahead.
Yes. Hey, Dan, I was wondering if you could comment on your EURs per 5,000 foot of lateral drilled. It seems like a couple of your competitors have increased their numbers and your number is still around 2.3 Bcf. I guess have you seen any data that would back up an increase in that?
Which ones?
Well, basically EURs in the Marcellus per 1,000 foot of lateral drilled, I guess the 14 Bcf EURs?
Well, we're not we're looking at our curve fits, Ray, and we have a 14 Bcf type of well that we've assigned and identified as our typical well because there's always lean, 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, I guess, do you have an estimate of how much capacity will be added in terms of total takeaway on big trunk lines over the next year or 2 in Northeast Pennsylvania?
Yes. I'll let Jeff handle it, Ray.
Thanks. Ray, I've got some numbers. There are more fund backs that like a Bentex 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 2 ways because you look at pipelines that are doing expansions like Texas Eastern that we do not have capacity on and we don't produce into, it does regionally influence where gas flows and what happens to pricing. And then we look more specifically at the pipelines we're connected to and will be connected to and the expansion projects that those pipes have.
Over the next few years, it's a big number and some of those 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. And 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 Barinchel of Jefferies. Please go ahead. Hi, good morning. One more marketing related question. So it looks like you're probably moving about $500,000,000 to maybe plus million to be considered as gas on short term contracts.
Can you talk about, say, 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 an example, this year, we're probably 80% of our production is sold under contracts that are existing. That number moves around. We have the market is quite dynamic in how it purchases gas. There's still a lot of buyers out there for 1 year deals and a lot of buyers for April, October deals and November, March deals and 1 month deals.
I mean, it's all over the place. But if it helps, we're about 80% sold for this year
currently. Okay. And then so then is the remaining 20 percent 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. Okay. And then, central compressor station, is there still a Phase 2 expansion there this year? And how do we think about it? Is that at the same sort of impact to lower fuel wide pressures?
There is a Phase 2 to Central. It is not this year. It's at the end of 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 of the effect, but we know that it's from the hydraulics perspective or from our planning teams, it's going to be very helpful.
Got it. Okay, thanks. The next question comes from Jack Aydin of KeyBanc. Please go ahead.
Hey, guys. Congratulations, Dan and team.
Hey, thanks, Jack.
Most of the questions were asked, but I got 3 to follow-up. A, when you did last year reserve, what Zikpad, what kind of booking did you book those wells at PDP or PUD on a PUD basis?
ZIC was done on a PDP basis for the majority of that.
Okay. So it's fair to assume that the performance of those wells that you just announced 2 miles and 5 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 fit 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 been derisked in your mind? 80. 80. Okay.
Next question I have for you is this. In the Marcellus over there in Susquehanna, you got different formation. Are you doing any different drilling, different pilot project to test the other formation beside the Marcellus or that or you don't need to do it now?
Well, we don't 1, 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. As you I know you've been asked this question before, but given kind of the dividend increase and the increase in production, how do you going forward, how do you look at balancing acceleration versus returning cash to shareholders as you kind of 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 that we made an initial attempt to do that with the 6th 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, at the same time, I'm not going to guarantee we're going to move it again in 2014, 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 talk in the future.
Do you have a longer term growth target for the company or?
In terms of dividend or just growth from the
Production growth.
We are working on a model out through 2017 that we'll finalize in the next month. But historically, we've kind of done it 1 year at a time, simply because there is a lot of noise.
Okay. All right. 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 takeaway 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've also seen some very good results in the eastern portion, again supporting our been our thesis all along, the derisking 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 some 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 and have a good