Good morning, and welcome to the Cabot Oil and Gas Corporation First Quarter 2013 Earnings Conference Call. All participants will be in listen only mode. Please note this event is being recorded. I would now like to turn the conference over to Dan Dingis. Please go ahead, sir.
Thank you, Maureen. I appreciate the introduction and good morning. Thank you for joining us for this call. I have a number of our executive management team with me in the room this morning. Before we start, let me say that the standard boilerplate forward looking statements included in the press release do apply to my comments today.
On the call today, we plan to cover several topics: our Q1 2013 operating and financial results an update on our expectations for all of 2013, followed by an update on operations in the Marcellus, Eagle Ford, Marminton and Parasol. Before I go into the details on these topics, let me first start with the highlights from last night's press release. For the Q1 of 2013, we produced 89.3 Bcfe, an increase of 50% over last year's comparable quarter and 13% over the Q4 of 'twelve. During the quarter, we set new quarterly records for production, revenue, operating cash flows and discretionary cash flows even in light of the relative low realized natural gas price. We continued to de risk our acreage position in the Marcellus, stepping out our drilling to the eastern portion a little further than we had previously, and these results are very consistent with our initial drilling area.
We also see noteworthy results from our Marminton program. Now for the quarter, moving into the financial and operational results, The company reported clean earnings of $54,200,000 or $0.26 per share, up 90% over last year's comparable quarter. Discretionary cash flow was $234,400,000 up 69% over last year's comparable quarter. The increases were driven by higher relevant excuse me, higher equivalent production and to a lesser extent higher realized crude oil prices that more than offset the weaker natural gas prices. Total per unit costs, including financing, were down 15% compared to the Q1 of 'twelve as all operating expense categories decreased on a per unit basis except for transportation and gathering and G and A expenses.
Transportation and gathering expenses were up slightly from additional Marcellus infrastructure expansion, while G and A increased due to the company's higher stock price and the resulting mark to market for liability awards. As I mentioned earlier, we had another record quarter for our production. As anticipated, Cabot averaged slightly less than a 1 Bcfe per day of total company net production. Our daily production moved up modestly from this average thus far in the Q2 as well completions continue to add to current production levels. We still believe that production will be somewhat range bound until late June when central compression becomes operational.
This long anticipated infrastructure addition was originally designed as a primary discharge station into Springville pipeline that goes down to the Transco line. However, combined with our newly installed infrastructure, Central will now assume the role of managing overall fuel pressure, while also acting as the primary discharge station Constitution pipeline, which is scheduled for March of 2015. In addition to Central, we will be seeing incremental new compression and dehydration facilities be commissioned throughout the remainder of 2013 putting us at a total gathering capacity of 2 Bcf per day by the end of the year as planned. On our guidance last night, we reaffirmed our full year equivalent production growth range of 35% to 50% for the year. Annualizing 1st quarter daily volumes gets you to the low end of our guidance.
Additionally, our cost guidance was also unchanged for the year as was our capital program of $950,000,000 to $1,025,000,000 On our hedging, in terms of the recent uptick in natural gas prices, we, like many, have utilized the late winter conditions and increasing prices to add to our hedge levels in both 'thirteen and 'fourteen. Today, we're about 62% hedged for the 2013 based on the midpoint of our guidance with no immediate plans to add additional hedges at this time for 'thirteen. For 'fourteen, we have 30 contracts or $300,000,000 collared for our natural gas hedges and will continue to be opportunistic adding to this position. Now let's move into the operational side of the business. In late March, we achieved a new 24 hour gross production rate in the Marcellus at a record of 1.054000000 Cubic Foot excuse me, 1.054 Bcf a day.
During the quarter, we turned in line 17 horizontal Marcellus wells. However, most of the wells that were turned in line offset some of our existing production as a result of the field pressure constraints. As I mentioned before, we expect the field pressure constraints to be relieved mid year when the central compression station comes online. Here are a couple of milestones from some of our wells that occurred during the quarter. We had our first well reach 8 Bcf of cumulative production in just six 67 days.
That kind of equates to about a 12,000,000 a day average. We also had our fastest wells to reach 3 Bcf and 6 Bcf of cumulative production in only 88 days and 2 70 days respectively. Also, we continue to add additional data points on our acreage position and as the press release highlighted, we brought online 2 wells in the quarter towards the east of our acreage and east of our Zick pad that recorded IP rates of over 16,000,000 a day and 22,000,000 a day for a 9 stage well and a 17 stage well respectively. Our completion efforts continue to improve with a significant uptick in activity during the quarter as highlighted with a 70% increase in completed stages from the first quarter of 2012 23% over the 4th quarter level. We currently have 4 29 stages completing, cleaning up or waiting to be turned in line along with an additional 279 stages waiting to be completed in the Marcellus.
We are also pleased to announce that our CNG station in Susquehanna became operable during the quarter. Our CNG initiative will not only result in reduced energy costs for the company, but it will certainly allow us to utilize efficiencies and environmental friendly natural gas. We currently have 44 fleet vehicles running on natural gas and we are awaiting technology to allow our water hauling trucks that have bigger power units in them to afford us the same opportunity. Operating remains on natural gas and when extensive pad drilling becomes a reality, which will happen towards the end of this year or early in 'fourteen, using natural gas to power the completion process will clearly lead to several cost saving opportunities. This is just another component of our efficiency program.
On the Marcellus infrastructure, we continue to see good progress on the infrastructure program by our midstream partner. Williams is on schedule with right of ways, permitting, construction and all the ancillary aspects of continuing and ongoing infrastructure build out. Recently, we had a few questions regarding the timing of our constitution pipeline. And although our actual FERC filing had been delayed a few months, we do expect to file with FERC in early June and we'll see no changes in the constitution in service date of March 2015. Now let's move to our South region.
In our South region, we continue to hold acreage in the Eagle Ford through our PureSO drilling. We have 3 rigs operating in the Pearsall. One rig has moved back to the Eagle Ford during the quarter and one in the Marminton. The Pearsall, it's still a young play and remains a science project for us, much like our Marminton in the early days. We have a thick column of hydrocarbon and continue to work on all aspects of drilling and completing a cost effective well.
The matrix porosity and finding the extensive fractures remains an issue as the wells are productive, but when you look at the rates compared to the cost so far, it makes it economically challenging when you compare that to our investment alternatives. The joint decision with Osaka is to finish up the drilling program as we had planned. And as such, the plan for the full year is to drill a total of 15 gross horizontal wells in the Pure Sol. Currently, we are drilling 3 wells, while 3 wells are completing or waiting on completion and 9 wells are producing online. The 30 day average production rate for the 6 wells that have produced for 30 days or more is over 600 Bcf Bcf, that'd be great 600 BOE per day with an average 50% oil cut.
We continue to refine the placement of laterals within the formation and try to optimize our completion procedures. Moving to the Eagle Ford, we don't have a whole lot to say on the Eagle Ford since we just moved the rig back there during the quarter. But to date, we have 43 wells producing in the Buckhorn area with 3 wells waiting on completion and one well currently drilling. While we've had limited activity, as I mentioned, in the Eagle Ford Duke to the Pearsall effort, Our last four wells produced at an average 24 hour rate of over 6.50 barrels of oil equivalent per day with an oil covenant of approximately 90%. During the quarter, we drilled our longest lateral to date in the Eagle Ford at 8,200 feet.
The well was completed with 30 stages and is still in the early stages of flowback. However, it is already providing oil rates above the field average IP. It's good data, but still very early. In the Marminton, during the quarter, we completed 5 wells with an average of 21 stages per well. We keep gaining efficiencies there.
These wells averaged an initial production rate of over 800 barrels of oil equivalent per day. So, we continue to be very pleased with our operation, the growth generated from our assets and progress we're making on a number of fronts. The Marcellus continues to deliver outstanding results and efficiency enhancements are just around the corner as we continue our planning for full pad development. The Marmaton cost reductions and well results are materially better and work in progress in the Pierce All continues with more drilling on the horizon. With the overall macro environment, for natural gas improving, which includes future natural gas demand expectations and our expanding production base, I think we are certainly in an excellent position to continue to deliver significant value to our shareholders.
With those brief comments, Maureen, I'll be more than happy to answer any questions.
Thank you. We will now begin the question and answer session. Our first question is Amir Arif from Stifel. Please go ahead.
Thanks. Good morning, guys. Good morning. Couple of quick questions. One, can you just tell me what was your backlog of completions at the start of 2013 and where you think that's going to be at the end of 2013?
Well, our backlog are you talking about just Marcellus?
Yes, just Marcellus.
Yes. Our backlog stays relative consistent throughout. If you look at the, say, 5 rigs running and we have several well, couple either 2 or 3 wells on the each pad at this time and we're drilling a little bit longer laterals and we are reduced our spacing on frac stages for our 13 program. We will continue to have all the 500 to 7.50 stages in the queue, if you will, just waiting for the rig to move off location and the frac crew to get lined up and scheduled to move on those locations that the rig move off. So Amir, it's a similar number as we have right now.
Okay. So it's not really it's not being constrained because of the compression or de high, it's more just getting the factories out, is that the first one?
Yes. It is just the operational logistics out of the field.
Okay. And then just a second question, if you can give any color on what your thoughts are on the free cash flow used as you start at length 14?
Well, we have had a number of questions in regard to that and we're certainly again cognizant of the fact of the excellent returns that we get from the Marcellus. So, in fact, we had a slide in our investor presentation that kind of outlines various different options. But when you look at a primary consideration and the most value creation would be to enhance our Marcellus capital contribution and expand that program in a material way, but we also look at either dividend increase, special dividends, share buybacks and but the free cash that we anticipate of any material sense will begin in earnest in 2014.
Okay. So it still sounds like you're leaning more towards accelerating activity. Is that a decision you still firm up in the second half?
Well, yes, yes, it is. It's a decision and a conversation that we continuously have internally and we also have ongoing work with the North region in looking at what is possible and still be able to maintain our level of efficiency we expect.
Okay. And just one final quick question. In the Wiley pad, have you drilled wells out there yet? Or are you just step are you slowly stepping out in that direction?
Yes. We've drilled wells, but we do not yet have the pipeline hooked up to that pad location. We are I can't tell you the exact status of that particular pipeline, but the expectation is early part of third quarter we ought to have a pipeline out there.
Sounds good. Thank you.
Our next question is from Pierce Hammond, Simmons and Company. Please go ahead.
Good morning. Hi, Pierce. Dan, just following up on the prior questioner, given the jump in gas prices, do you foresee any change in activity for this year or maybe pursuing that very large well pad?
It appears we have all been blessed with an uptick in the natural gas price. And when we have in our initial plan in our operation moving into 'thirteen, we thought about not only having one completion crew, but we had explored the opportunity early in the year actually towards the end of 'twelve of having a second completion crew in the field for a short period of time to just take care of some spread out wells that we had on a waiting on completion status. After we saw the towards the March period of time, we saw the opportunity for maybe a little bit higher gas prices. We have maintained that completion crew working for us and that was one of the catalysts that increased the number of stages that we are able to deliver 70% over the Q1 of 'twelve and a significant percentage over the last quarter of 'twelve also. So, we're looking at just how we keep that extra completion crew going as an option.
And we also have discussions ongoing to determine when we might want to bring a 6th rig into the field to start drilling off a given pad. It does not necessarily move up in the Q, the extensive pad drilling or pure pad drilling. What it does do though, it moves it up in theory because the rig, the 6th rig we'd move back in location would be capturing primary term acreage sooner, which would as a result allow us to start pad drilling sooner.
Great. Thank you. And then have you noticed any changes in service costs or just general service capacity in the Marcellus here recently with the uptick in gas prices?
No, we haven't. But keep in mind, the largest component of our cost out there are rigs and completion crews. And we are in kind of a unique area of the Marcellus out there and that equipment out there is going to be in that area and we think we get good pricing. We have a long term contract on one of the crews and we're using another as a spot crew, but we have not seen any increases in prices at this stage.
Thanks and congrats on a great quarter.
Thanks Peter.
Our next question is from Abhi Simha, Bank of America. Please go ahead.
Yeah. Hi. Thank you very much. Basically, I'm just filling for Doug Leggate here. So, an overall question, I'm just trying to see by when would you be done with down spacing testing in the morse less and well optimizations to shift gears to full development mode?
Well, in the Marcellus, we have remained spaced at 1,000 foot between the majority of the wells we've drilled. We have drilled several of the Upper Marcellus wells that we're staggering in between the Lower Marcellus wells at about 500 feet. Once we get on a full pad development, we are going to experiment with down spacing the wells to see what might be the most effective and efficient spacing in the field. And I'm sorry, I didn't get the latter part of your question, Abbie.
No. It was the same thing as about on the well optimization too like when would you be done with down spacing and well optimization when you're talking about different lateral lengths.
Yes. And again, the timing of this will be once we circle a rig back around to do the extensive pad drilling, which would be towards the latter part beginning the latter part of 'thirteen or the beginning of 'fourteen. And keep in mind, once we put a rig on location and say we're going to drill 10, 12, 14 wells, say we drill 10 wells, you're going to be you're going to have that rig on location for a good period of time before you can come back in and complete the each well. So, we're excited to move in that direction and we have extensive study ongoing to allow us to cut cost in a material way once we get to pad drilling.
Could you give us a sense on like on how much of your acreage in the Marcellus will have will be prospective for Upper Marcellus?
How much is prospective for the Upper Marcellus?
Yes, sir.
Well, we think we have Upper Marcellus across all of our acreage in Susquehanna. As you move to the very north end of our acreage and the entire section bends from 350 plus or minus in the middle part to the northern part to about a gross interval of 250 feet. We would look at those particular wells. We look at those particular wells in a standalone case to determine in today's return environment that we're trying to achieve whether or not our capital dollar is going to be spent there today or down the road to compete with the significant returns we're getting in the rest of the area. And Scott, correct me.
I think I mentioned I think I said Northeast. I should have said Northwest in our area where we have about 10% of our acreage up there that we we'd be looking at as lower Marcellus completions, but still going to have a science project on the upper Marcellus completions. Sure.
Thank you very much. That's all I have. Thanks.
Our next question is from Gil Yang, Discern. Please go ahead.
Thanks. Good morning.
Hi, Gil. The couple of
wells that you drilled that you cited to east the Lick pad were is there the 16.3 on 9 stages versus the 22.2 on 17 stages, Could you characterize the difference in the per stage volume? Is it a rock quality issue? Or is there a production engineering issue or a constriction sort of issue that would account for the difference in performance?
Well, at each stage, I think the average on one is $1,300,000 a day and the average on the other is $1,800,000 a day. It might be Gil, it might be just the immediate connectivity to the fractures in a particular area, maybe several stages, maybe all the stages, but that delta for us does not we don't have the ability to discern that level of difference between the wells. But certainly each of the wells on a per stage basis actually on average is a little bit higher than our entire field.
Okay, great. The issue of pad drilling, drilling dozen or so wells from one pad in the future. Can you talk about given that your wells they come out so strongly you're already knocking off existing wells off of in terms of production. If you bring on a dozen wells at the same time, so to speak, how will the cost savings of sitting on a pad versus issues surrounding knocking nearby wells offline repeatedly play out? And does it require upsizing infrastructure that could increase costs?
Yes. And I'll chuck the ball to Jeff to respond to you after my brief comments. But we have a high expectation of significant volumes coming from a fully developed pad site as you might suspect. We have been discussing exactly your question with Williams for an extended period of time. And through those discussions, as we develop the infrastructure, as we continue to look at all the options that we can create in the field with the locations of compressors, dehives, for example, the central compressor, we are taking into consideration the expectation of high rates off a pad site and our ability to have the longer producing wells that have lower pressure to remain producing.
And I'll let Jeff fill in the blanks.
Well, a few more blanks, but Dan did a good job because we have been working on this for 18, 24 months with Williams doing the hydraulic engineering necessary to make sure these pads are able to produce at 100% plus capture some of the older wells at the same time. And we're basically doing that with more compression and larger diameter pipe and moving the pipelines and additional taps in the Tennessee, new stations, I mean, it's the whole ball of wax of activity that we're out there doing today to grow capacity to the 2 Bcf level by the end of this year. But there's a lot of hidden projects. In fact, we have no less than 60 projects going on to facilitate the pads when we get to that point. They're going to be all over the system.
So it's a massive undertaking. But we have I think we have a very good plan in place to address the pad completions.
And presumably the drilling cost savings outweigh the extra cost of the infrastructure you're putting in place?
So the infrastructure in place is 100% Williams cost and we have a transportation fee that is netted from our gross price.
Right. Right. Okay. Thanks.
Thank you.
Our next question is Matt Portillo, Tudor, Ticker and Holt. Please go ahead.
Good morning, guys.
Hi, Matt.
Just a few quick questions for me. I was hoping that you could give us a little color on your production constraints today. You mentioned that some of the wells are being produced at a constraint rate or they're getting knocked off from pressure. So just curious if you could kind of quantify that for us? And then as you get of the compression facilities on in June, I was hoping to get a little bit of color on how that could potentially affect your gross volumes in the Marcellus heading into the back half of this year?
Okay. On the first question on the production constraints. And again, it's just met nerve or physiologically, if you look at the higher rates coming on and to your question, knocking off the other wells, The line pressure in the field has remained high. We I think are still free flowing even some of our gas directly into the pipeline, not going through compression at this time, but with our relatively high line pressure already and the wells producing into that, when we bring on and have put on some of these other wells, we might increase our line pressure anywhere from 100 to 150 pounds and obviously that delta inhibits the same flow from those existing wells. I can't really put an amount on the amount that we knock off.
I mean, it would be a simple math project. I don't have it. Say, if a well was producing 5,000,000 a day and you brought on a 20,000,000 a day well, instead of netting $25,000,000 out of it, you might be netting $23,000,000 or $21,000,000 I don't know something to that effect, but I really, Matt, don't have the number at my fingertips. And your question on the compression facilities was what exactly?
Just as that compression comes on stream, could you give us I guess a bit of color on how that could potentially allow you to see an uplift in your volumes? So just trying to get a better sense of if you're producing about a BE a day of gross production in the Marcellus, how does that production that compression coming on stream help change that trajectory in the back half of this year?
Well, and there's 2 components to that. 1 is the central station that is going to allow us to reduce the majority of our fuel line pressures. And so we may see an enhancement to our production as a result of just going from £800 or 900 to whatever we can lower the line pressure to reducing that £100, 200 or whatever we might be able to achieve. So we think we might be able to see something from that. And as we put ongoing compression and dehi in strategic spots in the field in those immediate areas, we're certainly going to allow each of the wells to produce into a lower line pressure than you might if we didn't have those compressors in that area.
Jeff, I don't know if you want to
add anything else? One last comment. Other factor that is involved here is that as we build out the infrastructure to the extremities of the acreage position, The older wells are naturally located closer to some of the compressor stations and so the extensions of the pipeline that are going out to the newer wells it's naturally bound to happen that the newer wells are going to push back some of the older wells offline until we get the line pressure issue corrected throughout the system. So that's something that all producers face as they start in one area and build out throughout their acreage position.
Great. And then just on switching gears quickly to the Pure Sol. With the wells you have on stream today, could you guys give us I guess an idea of how you think about kind of EURs there? And then also on the updated Marminton wells, just curious how you guys are thinking about the EURs on those wells as well?
Well, first I'll start with the Marminton. The Marminton is a we've seen some really good results in the Marminton. And it's looking like between our, if you will, shorter laterals versus our extended laterals, it looks like that we can get maybe a 50% increase in our EUR to be up in the 230 or higher range. We don't have a number of those wells producing long enough to where I can lock in that EUR. But we are very pleased with what we're seeing in the Marminton.
In the Pearsall, still early to tell on the Pearsall, because we have tried so many different things, whether it be the landing point, and this is different than what we're doing in the Marminton, whether it be the landing point where we're drilling the wells or whether it's be drilled in the den position much further north in the debt position, which is more oily or further south in the debt position, which is more gas liquids attached to the further south along with the different techniques that we're applying to the completion. So to give a range of EURs in the Pearsall, I'm just reluctant to do right now because of all the variability.
Okay. And then just my last question, just maybe a little bit more color on the rig count for the Marcellus. Could you give us, I guess, some color on timing of when you hope to get your 6th rig in place? And then is it reasonable to think in 2014 that you may be able to accelerate to an 8 rig count? Or is that a little too early to tell just given the constraints you've seen?
Thank you.
Yes. Thank you, Matt. Well, the rig count of the Marcellus what we've been looking at is, 1, I mentioned the efficiencies and making sure we can maintain the efficiencies and consistency of our program. And some of that involves just clearing the locations for a rig on a consistent basis. It looks like it includes the scheduling of the completion, so we won't have stranded dollars out there any longer than we have to.
It also has the coordination with Williams on getting the gathering lines to the locations if we move our program up a little bit and looking at all the aspects of that. But what we're looking at is possibly towards the early fall, we might be bringing in a rig, a 6th rig to the Marcellus. And in regard to 'fourteen, still early to tell definitively what we might do on 'fourteen. We've been very pleased with the uptick in gas prices through this shoulder period. We have some collars in place that protect us on some volumes on the downside into a 'fourteen now.
So we are at what we might be able to do on our program expansion
on our
'fourteen period, but little bit early to say whether or not we'd go to 7 rigs or 8 rigs.
Thank you.
Thanks, Matt.
Our next question is Bob Brackett, Bernstein Research. Please go ahead.
A question on the PureSol program. Those 15 gross wells, can you talk about your out of pocket costs sort of net of the drilling carries? And where will you be at the end of the year in terms of drilling carries from Osaka?
Well, we will we have a expense interest in the wells that we've drilled so far and the wells that we will drill between now and the remainder of the year. We have a 9.75 percent expense interest in those wells.
Okay. Great. Thank you. Yes. Thank you.
Our next question is Lewis Baltimore, Macquarie. Please go ahead.
Yes. It looks like you're starting to move south into Wyoming County where some other operators build some very productive Marcellus wells. And I was just wondering if you could comment on what you've been seeing from your wells down there and how big your position is?
Well, we include in Wyoming County, the acreage that's directionally towards, say, Citrus acreage, which has the other top five of twenty wells in 2012 and Cabot has the other 15. But we like that acreage and we do not anticipate any difference in that acreage down there than we Thank you. Our next question
Thank you.
Our next question is Gordon Gouthat, Wells Fargo. Please go ahead.
Good morning, guys. Good morning, Gordon. Question on the eastern side of your acreage in the Marcellus. How do you anticipate the delineation of that? Obviously, some are dependent on infrastructure, but how do you foresee that proceeding over the coming quarters years?
Once we get our infrastructure build out going in that direction and the material size to where we would allocate the rig and completion crews over there to be able to monetize that investment, We do not see any change in how we proceed with the Eastern acreage than what we're developing right now. It'd just be a natural extension as we grow from where we started drilling and started our infrastructure as we grow out to towards the East.
And it looks as if you've got a number of things coming from the infrastructure standpoint later this year. Is that directed towards the eastern side of the acreage? Or any comments you can make as far as the timing of the infrastructure build out as you move east?
Yes. I'll let Jeff field that, Gordon.
Yes. I think if I heard you correctly, the well, let me start by saying that on the Zik area in the eastern side, it's probably where we are best positioned with excess capacity. So for example, when we talk about today, we have about 1.4 Bcf a day of capacity throughout the system. It's only in the ZIC area and maybe a little bit to the north in the Holly area that we do have excess capacity. So that's a good thing.
And one of the we mentioned some smaller projects in the press release. It's actually in the Zick area, it's the 2nd phase of a larger project that is getting us some additional compression on the east side around Zik. And so again, that's a very good thing. So we feel real good about the eastern side in terms of capacities going forward.
Okay. And then last question for me. Last night in the operations press release, there was a comment about looking for ways to further extract value from your underappreciated assets. So just wondering if you could provide any color on your thought process to what that what's beyond that comment?
Well, we have and that comment was kind of directed towards our Marminton and what we see there is good results, good returns. We're not actively marketing our Marminton at this stage, but if in fact it would be a transact if a transaction was to be had, we would certainly look at the Marminton as an area that we would consider and utilize those dollars to enhance some of the other areas of our operation. Again, let me emphasize, we're not actively marketing the Marminton, but being underappreciated is really simply the fact that at 90% oil in those wells and the well cost $3,000,000 to $4,000,000 depending on the lateral lengths and the number of stages, it's delivering very good rate of returns.
Okay. Thank you.
Our next question is Bishu Perincheril from Jefferies. Please go ahead.
Hi, good morning.
Can you give us an update on how do you take on the capacity of the basins of Marcellus?
And I'm sorry. Biju, I can't hear you real well.
Can you hear me now?
Yes, yes, that's good.
Yes. Good morning. Can you give us an update on your takeaway capacity out of the Marcellus today? And any new projects or incremental capacity coming on until the Constitution?
Yes, Biju, that is a question that's directly up Jeff Hudson's alley.
Okay. Thanks for the question. The just to be clear, when some people talk about takeaway, they talk about the downstream interstate pipeline capacities that we're utilizing and marketing our gas. So I'm assuming that is your question and not necessarily the infrastructure?
Correct. It's yes, It's interstate pipelines, right, not the gathering systems.
Okay. So currently, we are producing just round numbers into Marcellus, the BCF and about approximately $500,000 of that goes down to Transco and $400,000 and some change stays on Tennessee Gas Pipeline and the remainder heads up to Millennium Pipeline. So as you know, we've been blessed with 3 very large interstate pipeline markets within 30 miles of our fields in either direction. So that's a great place to start. It's a huge advantage.
But as far as firm capacity contracts, we own just shy of 400,000 a day of Feet ourselves and those firm contracts take gas out of Susquehanna County to different market areas. In fact, as far over in the East Ohio area and throughout Pennsylvania and into the East, we actually have over 100,000 day capacity that goes lease Susquehanna County and goes into the Boston area. We do, however, have a lot of long term contracts where we use sales contracts where we use other people's firm to move our gas and that's predominantly down on the Transco pipeline. So we feel like we're in a pretty good shape with long term contracts using other people's firm and the firm that we own ourselves. That's really been a huge advantage to date.
So if you're talking about adding going to 6 or 7 rigs eventually, I guess that would largely, I mean, using your customers' capacity to move gas. Is
That will always be part of all producers in the Marcellus package of opportunities. Because if you think about it, the firm contracts, the historic firm contracts are all owned by the marketplace, the place, the LDCs throughout New England and even in the New York area and down to the Baltimore and Washington D. C. Area. And what the producers have done is we've taken out a lot of backhaul contracts and move gas the opposite direction that the utility uses.
But utilities will always be a huge part of our business with because they own the original transportation, whether it's 4, 5, 6 Bcf a day of capacity. Now some of the nuances has been the expansions. As you know, the Leidy line expansion is going to take 600,000 to 700,000 a day down to the Carolinas. We have a role in that. We have a role in Columbia Extension into the DC and the Baltimore area.
And of course, we have Constitution Pipeline that's going to move 0.5 Bcf a day of Cabot Marcellus gas in 2015 into 3 new interstate markets. So at the end of the day, we'll have our gas positioned to deliver into 6 very large diameter state pipeline market areas. And that's been our plan for 2 years now and we think it's a very solid plan.
And the Spring Mill system that's moving gas down to Transco, is that a 12 year utilization now? Or is there room to room to expand that?
Okay. So it's a 24 inches high pressure pipeline and we're moving in excess of 0.5 Bcf a day down that pipe. We will have to there are plans to add a little bit more horsepower so that we can get up to around the 600 level. But basically that's the extent of that pipe unless it's looped or some other enhancements may be made to it.
Okay. All right. Thanks. That's all I had.
Thanks, BJ.
Our next question is Brian Singer, Goldman Sachs. Please go ahead.
Thank you. Good morning.
Hi, good morning. Three small
questions under the context of thinking about capital allocation with the potential 6th rig.
The first is, you've talked in
the past about trying to making sure you get your drilling plan, sometimes even 2 years ahead to your key midstream providers. What is the lead time you feel like is needed to ensure reliability? And what's the risk around it all kind of being ready, as you talked about earlier for 6 to rig potentially 3 or 4 months away? I guess that's question 1. Question 2 is just making sure whether the 6 to rig for portion of the year is in your CapEx budget or not and if you're seeing any efficiencies that would offset that.
And then question 3 would just be how you're thinking about dividends or returning cash to shareholders in the context of a fixed rate and higher gas prices?
Okay. Well, the risk of planning is low. Let me say that differently. We have planned to add our additional rigs, additional activity to our program. And as we have stated, that we are actually working on 2015 with Williams as we speak.
So, the risk of getting things lined up is and implementing a plan that would allow us to utilize fully utilize a 6th rig is fairly low. What I'd be referring to on getting all the bells and whistles and ducks in a row for a 6th rig is just to confirm that we will be able to have the right people in place and we will utilize our in house folks, GDS that handles a great deal of our operations, not only the water hauling aspects, but road building and location building aspects of it just to make sure we can get ahead of it in all just the nuts and bolts of the front end work to move a rig on, Brian. But in the permitting side of it, we have I don't have a high degree of risk on the permitting side. The North region has been great at staying ahead of their permit requests over and above the budgeted program, say 85 wells that we have budgeted this year. So, I feel good about that and would not think that regulatory issues would get in the way.
A 6th rig has not been budgeted in our program at this stage. We might have had anticipation of maybe a very short time in December or something bringing in the 6th rig, but for all intents and purposes, a 6th rig has not been budgeted in the program. And what was your last question, Brian? Dividend. Oh, dividend.
Scott wanted to answer that one.
Brian, in terms of clearly the priority in as we approach this higher level of free cash flow is to explore accelerating the reinvestment in the Marcellus. We haven't gone much farther on terms of a special dividend, increasing the dividend yield or a buyback at this point in time. Again that as Dan said earlier that's more of a 14 decision. We have spent some time with some experts in terms of the impact accretive, dilutive, best course of action. And quite honestly on all three of them based on where we're at, they kind of came to the decision that it was and again not ho but it didn't have the impact that it can have in some other applications because of the opportunity set related to the reinvestment back in the business particularly the Marcellus.
So haven't made a final decision. And again, we'll kind of see as we flush out the 14 plan and the anticipation of free cash flow together with anything else we do before we come to a final decision on dividends.
Thank you.
Thanks, Brian.
Having no further questions, this concludes our question and answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.
Thanks, Maureen, and thanks everybody for spending their time on this conference call. We're very optimistic. We see a lot in the marketplace that is directing our attention to future demand for our natural gas. I think we've said before that we know we have supply out there, we need to enhance the demand and all the ancillary areas that I spend time looking at, I'm fairly excited about the increased demand that we're going to have in natural gas down the road. Again, appreciate it and look forward to the visit on the Q2 conference call.
Thanks.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.