Coterra Energy Inc (CTRA) 2013 Q1 法說會逐字稿

Good morning, and welcome to the Cabot Oil & Gas Corporation first-quarter 2013 earnings 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. 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 boiler plate 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 first-quarter 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, Marmaton and Pearsall. Before I go into the details on these topics, let me first start with the highlights from last night's press release. For the first quarter of 2013, we produced 89.3 Bcfe, an increase of 50% over last year's comparable quarter, and 13% over the fourth quarter of '12. During the quarter, we set new quarterly records for production, for 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 by 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 Marmaton program.

Now for the quarter. Moving into the financial and operational results, the Company reported clean earnings, $54.2 million or $0.26 per share, up 90% over last year's comparable quarter. Discretionary cash flow was $234.4 million, up 69% over last year's comparable quarter. The increases were driven by 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 first quarter of '12, as all operating expense categories decreased on a per unit basis, except for transportation and gathering, and G&A expenses. Transportation and gathering expenses were up slightly from additional Marcellus infrastructure expansion, while G&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 production, as anticipated. Cabot averaged slightly less than 1 Bcfe per day of total Company net production. Our daily production moved up modestly from this average thus far in the second quarter, 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 field pressure, while also acting as the primary discharge station to the Constitution Pipeline, which is scheduled for March of '15. In addition to Central, we will be seeing incremental new compression and dehydration facilities be commissioned throughout the remainder of '13, 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 first-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 expected capital program of $950 million to $1.025 billion. 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 '13 and '14. Today we are 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 '13. For '14, we have 30 contracts for $300 million collared for 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 1.054 million 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 midyear when the Central Compression Station comes on line.

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 667 days. That equates to about a 12 million-a-day average. We also had our fastest wells to reach 3 Bcf and 6 Bcf of cumulative production in only 88 days and 270 days, respectively. Also we continue to add additional data points on our acreage position. And as the press release highlighted, we brought on line 2 wells in the quarter towards the east of our acreage and east of our Zick pad that recorded IP rates of over 16 million a day and 22 million 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, and 23% over the fourth-quarter level. We currently have 429 stages completing, or 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 the energy 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 (technical difficulty) on natural gas and when extensive pad drilling becomes a reality, which will happen towards the end of this year or early in '14, 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 an 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 will 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 Pearsall drilling. We have three rigs operating in the Pearsall. One rig has moved back to the Eagle Ford during the quarter, and one in the Marmaton. The Pearsall is still a young play and remains a science project for us, much like our Marmaton 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 Pearsall. Currently we are drilling three wells, while three wells are completing or waiting on completion. And nine wells are producing on line. The 30-day average production rate for the six wells that have produced for 30 days or more is over 600 Bcf -- (laughter) Bcf, that would be great -- 600 Boe per day, with an average of 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 a rig back there during the quarter. But to date, we have 43 wells producing in the Buckhorn area, with three wells waiting on completion and one well currently drilling. While we have had limited activity, as I mentioned, in the Eagle Ford, due to the Pearsall effort, our last four wells produced at an average 24-hour rate of over 650 barrels of oil equivalent per day, with an oil cut 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 a 30 stages, and is still in the early, early stages of flow back. However, it is already providing oil rates above the field average IP. It is good data but still very early. In the Marmaton, during the quarter, we completed five 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 the progress we are 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 Pearsall continues, with more easy 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 will be more than happy to answer any questions.

Thank you. We will now begin the question-and-answer session.

(Operator Instructions)

Amir Arif from Stifel.

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 the Marcellus?

Yes, just the Marcellus.

Our backlog stays relatively consistent throughout. If you look at the, say 5 rigs running, and we have several wells, a couple, either 2 or 3 wells on each pad at this time.

And we are drilling a little bit longer laterals and we are -- reduced our spacing on frac stages for our 2013 program we will continue to have 500 to 750 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 moves on. It is a similar number as we have right now.

Okay, so it is not being constrained because of the compression or dehy, it's more just getting the frac crews out? Is that a fair statement?

Yes, it is. Just the operational logistics out in 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 use as you start up in 2014.

Well, we have had a number of questions in regard to that. And we are certainly, again, cognizant of the fact of the excellent returns that we get from the Marcellus.

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. 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 still to firm up in the second half?

Yes, it is. It is 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 [respect].

Okay. And just final quick question. In the Reilly pad, have you drilled wells out there yet? Or you're just totally stepping out in that direction?

Yes, we have drilled wells, but we do not yet have the pipeline hooked up to that pad location. We are -- oh, I can't tell you the exact status of that particular pipeline. But the expectation is the early part of third quarter we ought to have a pipeline out there.

Sounds good, thank you.

Pearce Hammond, Simmons Company.

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?

Pearce, 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 2013, we thought about not only having one completion crew, but we had explored the opportunity early in the year -- actually towards the end of 2012 -- 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 first quarter of 2012, and a significant percentage over the last quarter of 2012 also. So we are 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 sixth rig into the field to start drilling off a given pad.

It does not necessarily move up in the queue to the extent that pad drilling or pier pad drilling. What it does do, though, it moves it up in theory, because the sixth rig we would 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. 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 are 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, Pearce.

Abhi Sinha, Bank of America.

Thank you very much. Basically I'm just filling for Doug Leggate here. On an oil question, I'm just trying to see by when would you be done with down-spacing testing in the Marcellus and well optimizations to shift gears to full development mode?

In the Marcellus, we have remained spaced at 1,000-foot between the majority of the wells we have drilled. We have drilled several of the upper Marcellus wells that we are 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 did not get the latter part of your question, Abhi?

It was the same thing as about on the well optimization too, like when would you be down-spacing and well optimization when you are talking about different lateral lengths.

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 2013, or the beginning of 2014. And keep in mind, once we put a rig on location, and say we are going to drill 10, 12, 14 wells -- say we drill 10 wells. You're going to have that rig on location for a good period of time before you can come back in and complete each well.

But we are excited to move in that direction. And we have an extensive study ongoing to allow us to cut costs in a material way once we get to pad drilling.

Could you give us a sense on how much of your equipment in the Marcellus will have a little bit prospective for upper Marcellus?

How much is prospective for the upper Marcellus?

Yes, sir.

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 thins 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 would look at those particular wells in a standalone case to determine in today's return environment that we are 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 are getting in the rest of the area.

And Scott, corrected me. 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 would 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 is all I have.

Thanks.

Gil Yang, DISCERN.

The couple of wells that you drilled -- that you decided to -- east of the Zick 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 there a rock quality issue? Or is there a production engineering issue, or a constriction sort of issue that would account for those difference in performance?

Each stage -- I think the average on one is 1.3 million a day. And the average on the other is 1.8 million a day. It might be, Gil, just the immediate connectivity to the fractures in a particular area of maybe several stages, maybe all of 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 a dozen or so wells from one pad in the future. Can you talk about -- given that your wells, they come on so strongly, you are 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 off line repeatedly play out? And does it require upsizing infrastructure that could increase costs?

Yes. And I will chuck the ball to Jeff to respond to after my brief comments.

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. 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, dehys.

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. I will 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 months, 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. We are basically doing that with more compression and larger diameter pipe and looping of pipelines, and additional pass into Tennessee, new stations. I mean, it's the whole ball of wax of activity that we are out there doing today to grow the capacity to the 2 Bcf level by the end of this year.

But there is 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 are going to be all over the system, so it is a massive undertaking. But I think we have a very good plan in place to address the pad completions.

Good. And then, presumably, the drilling cost-savings outweigh the extra cost of the infrastructure you are putting in place?

Well, the infrastructure in place is 100% Williams' cost. And we have a transportation fee that is netted from our gross price.

Right, okay, thanks.

Thank you.

Matt Portillo, Tudor, Pickering & Holt.

I was hoping that you could give us a little color on your production constraints to date. You mentioned that some of the wells are being produced at a constrained rate or they are getting knocked off from pressure. So just curious if you could quantify that for us?

And then as you get some 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. Again, 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 pipelines, 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 brought 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. It would be a simple math project. I don't have it. Say if a well was producing 5 million a day and you brought on a 20 million-a-day well, instead of netting 25 million out of it, you might be netting 23 million or 21 million. I don't know, something to that effect.

But I really, Matt, don't have the number at my fingertips. And you're question on the compression facilities was what exactly?

Just as that compression comes on stream, could you give us 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 are producing about a B a day of gross production in the Marcellus, how does that production or that compression coming on stream help change that trajectory in the back half of this year?

There is two components to that. One is the central station that is going to allow us to reduce the majority of our fueled-line pressures. We may see an enhancement to our production as a result of just going from 800 or 900 pounds, to whatever we can lower the line pressure to. Reducing that 100, 200 pounds, 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 dehy in strategic spots in the field, in those immediate areas, we are 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, do you want to add anything else to that?

One last comment. The 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 is naturally bound to happen that the newer wells are going to push back some of the older wells off line until we get the line pressure issue corrected throughout the system. That is 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 Pearsall. With the wells you have on stream today, could you guys give us an idea of how you think about EURs there? And then also on the updated Marmaton wells, just kind of curious how you guys are thinking about the EURs on those wells as well?

Well, first I will start with the Marmaton. The Marmaton is a -- we have seen some really good results in the Marmaton. And it is 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 are seeing in the Marmaton.

In the Pearsall, still early to tell on the Pearsall because we had tried so many different things, whether it be the landing point -- and this is different than what we are doing in the Marmaton -- whether it be the landing point where we are drilling the wells, or whether it's be drilled in the depth position, much further north in the depth position, which is more oily. Or further south in the depth position, which is more gas liquids attached to the further south, along with the different techniques that we are applying to the completions. 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 some color on timing of when you hope to get your sixth rig in place? And then, is it reasonable to think in 2014 that you may be able to accelerate to an eight rig count? Or is that a little too early to tell, just given the constraints you've seen? Thank you.

Thank you, Matt. The rig count in the Marcellus, what we've been looking at is -- one, I mentioned the efficiencies and making sure we can maintain the efficiencies and consistency of our program. And some of that involves 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 are looking at is possibly towards the early fall, we might be bringing in a rig, a sixth rig to the Marcellus.

And in regard to 2014, still early to tell definitively what we might do on 2014. We have 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 2014 now.

So we are looking at what we might be able to do on our program expansion for our 2014 period. But a little bit early to say whether or not we would go to seven rigs or eight rigs.

Thank you.

Thanks, Matt.

Bob Brackett, Bernstein Research.

Got a question on the Pearsall program, those 15 gross wells. Can you talk about your out-of-pocket cost in 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?

We have an expense interest in the wells that we have drilled so far and the wells that we will drill between now and the remainder of the year. We have a 9.75% expense interest in those wells.

Okay, great, thank you.

Yes, thank you.

Louis Baltimore, Macquarie.

It looks like you are starting to move south into Wyoming County, where some other operators have drilled some very productive Marcellus wells. And I was just wondering if you could comment on what you have been seeing from your wells down there and how big your position is?

Well, we include in Wyoming County the acreage that is directionally towards, let's say Citrus acreage, which has the other top 5 of 20 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 see where we are drilling right now.

Thank you.

Gordon Douthat, Wells Fargo.

Question on the eastern side of your acreage in the Marcellus. How do you anticipate the delineation of that? Obviously you're dependent on infrastructure. But how do you foresee that proceeding over the coming quarters and years?

Once we get our infrastructure built-out going in that direction and the materials sized 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 are developing right now. It would just be a natural extension as we grow from where we started drilling and started our infrastructure, and as we grow out towards the east.

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 will let Jeff field that.

Yes. I think if I heard you correctly -- well, let me just start by saying that on the Zick 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 is only in the Zick area, and maybe a little bit to the north in the Holly area, that we do have excess capacity. So that is a good thing.

And one of the -- we mentioned some smaller projects in the press release. It is actually in the Zick area, it is the second phase of a larger project that is giving us additional compression on the east side, around Zick. So again, that is 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 under-appreciated assets. So just wondering if you can provide any color on your thought process of what that -- what is behind that comment?

That comment was kind of directed towards our Marmaton, and what we see there are good results, good returns. We are not actively marketing our Marmaton at this stage. But if, in fact, it would be a transaction -- if a transaction was to be had, we would certainly look at the Marmaton 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 are not actively marketing the Marmaton. But being under-appreciated is really simply the fact that 90% oil in those wells -- and the well costs $3 million to $4 million, depending on the lateral lengths and the number of stages -- it is delivering very good rate of returns.

Okay, thank you.

Biju Perincheril from Jefferies.

Could you give us an update on your take of the capacity on basin in the Marcellus and --

I am sorry, Biju, I can't hear you real well.

Can you hear me now?

Yes, that's good.

Can you give us an update on your take of the 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 is directly up Jeff Hutton's alley.

Thanks for the question. (laughter) Just to be clear, when some people talk about take-away, they talk about the downstream interstate pipeline capacities that we are utilizing in marketing our gas. So I'm assuming that is your question, and not necessarily the infrastructure?

Correct. It is interstate pipelines, right, not the gathering systems.

Okay. So currently we are producing -- and this is just round numbers in the Marcellus, the Bcf. And about approximately 500,000 of that goes down to Transco. And 400 and some change stays on Tennessee Gas Pipeline, and the remainder heads up to Millennium Pipeline.

As you know, we have been blessed with three very large interstate pipeline markets within 30 miles of our field in either direction. So it is 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 FT ourselves. And those firm contracts take gas out of Susquehanna County to different market areas. In fact, as far over in East Ohio area and throughout Pennsylvania, and then to the east, we actually have over 100,000 of that capacity that goes -- leaves Susquehanna County and goes into the Boston area.

We do, however, have a lot of long-term contacts where we use -- sales contracts -- where use other people's firm to move our gas. And that's predominately down on the Transco Pipeline. So we feel like we are in a pretty good shape with long-term contracts, using other peoples' firms and firm that we own ourselves. That's really been a huge advantage to date.

So if you're talking about adding or going to six or seven, eight rigs, eventually, I guess that would largely mean using your customers' firm capacity to move gas. Is that --?

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 LDCs throughout New England, and even in the New York area and down to the Baltimore and Washington, DC area. And what the producers have done is, we've taken a lot of backhaul contracts and moved gas the opposite direction that the utility uses.

Utilities will always be a huge part of our business because they own the original transportation, whether it is 4 or 5, 6 Bcf a day of capacity. Now some of the nuances have been the expansions. As you know, the Leidy Line expansion is going to take 600,000, 700,000 a day down to the Carolinas. We have a role in that. We have a role in the Columbia expansion into the DC and Baltimore area.

And of course, we have Constitution Pipeline that is going to move 0.5 Bcf a day of Cabot Marcellus gas in 2015 into three new interstate markets. So at the end of the day, we will have our gas positioned to deliver into six very large diameter state pipeline market areas. And that has been our plan for two years now. We think it is a very solid plan.

And the Springville system that is moving gas down to Transco, is that at total utilization now? Or is there room to expand that?

Okay, so it's a 24-inch high-pressure pipeline, and we are 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 is the extent of that pipe unless it is looped, or some other enhancements may be made to it.

All right, thanks. That is all I had.

Thanks, Biju.

Brian Singer, Goldman Sachs.

Three small questions, under the context of thinking about capital allocation with a potential sixth rig. The first is, you have talked in the past about trying to -- making sure you get your drilling plan, sometimes even two years ahead, to your key midstream providers. What is the lead time you feel like is needed to ensure reliability? And what is the risk around it all being ready, as you talked about earlier, for a sixth rig, potentially three or four months away? I guess that's question one.

Question two is just making sure whether that sixth rig for a portion of the year is in your CapEx budget or not, and if you are seeing any efficiencies that would offset that.

And then question three would just be how you're thinking about dividends or returning cash to shareholders in the context of a sixth rig and higher gas prices.

Okay, well on the risk of planning is low. Excuse me, 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 fully utilize a sixth rig is fairly low. What I would be referring to on getting all the bells and whistles and ducks in a row for a sixth 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, 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 programs 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 sixth 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 sixth rig. But for all intents and purposes, a sixth rig has not been budgeted in the programming. What was your last question, Brian?

Dividend.

Oh, dividend. Scott wanted to answer that one.

Brian, in terms of -- clearly the priority 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, as Dan said earlier, that is more of 2014 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 are at, they kind of came to the decision that it was -- and again, not ho-hum, 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 will see as we flush out the 2014 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 are very optimistic. We see a lot in the marketplace that is directing our attention to future demand for natural gas. I think we have 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 am fairly excited about the increased demand that we are going to have in natural gas down the road.

Again, I appreciate it, and look forward to the visit on the second-quarter conference call. Thanks.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.