Coterra Energy Inc (CTRA) 2014 Q1 法說會逐字稿

Good morning and welcome to the Cabot Oil & Gas Corporation first quarter 2014 earnings conference call. All participants will be in a listen-only mode.

(Operator Instructions)

Please note this event is being recorded.

I would now like to turn the conference over to Dan Dinges, Chairman, President, and CEO. Please go ahead, sir.

Thank you, Emily, and good morning to all. I appreciate you joining us for this call. I do have several of the Cabot executive team members with me today.

Before we start, let me say the standard boilerplate language on the forward-looking statements included in the press release, does apply to my comments today.

To begin, I'd like to first touch on a few of the financial and operating highlights from the first quarter that were outlined in this morning's press release. And those are the production during the first quarter averaged 1.332 million cubic feet per day, an increase of 34% over the first quarter of 2013. As we guided on the year-end call in February, this volume is relatively flat to our fourth quarter production levels, which was primarily a result of compressor station downtime in the Marcellus, due to the severe weather we had, and the number of wells we had scheduled to turn in-line. When adjusting for our Mid-Continent and West Texas asset sales in the fourth quarter of last year, we grew the daily production by a few percentage sequentially.

Discretionary cash flow for the quarter was approximately $320 million, an increase of 36% compared to the first quarter of 2013, and a 12% increase over the fourth quarter. Net income, excluding select items, was approximately $110 million, an increase of over 100%, compared with the first quarter of 2013, and a 47% increase over the fourth quarter. These record-setting metrics were further enhanced on a per-share basis due to our reduction in shares outstanding, resulting from our repurchase of 4.8 million shares in the fourth quarter of last year.

Of significant note, and I do think worth repeating, during the first week of this month, we reached a milestone in the field of 1 Bcf of cumulative gross production for these assets, which is particularly impressive, given we began flowing production from our first Marcellus well less than six years ago, and we have never operated more than six rigs, or produced from more than 290 horizontal wells in the play during this time. Certainly a milestone that recognizes the productivity of these unique assets. It's not going to be many assets out there that can boast those numbers.

Operationally, we do continue to demonstrate best in class execution across both our areas we're allocating capital. That's in the Marcellus and Eagle Ford program. In the Marcellus, we average slightly over 1.2 Bcf per day of net production during the first quarter, in spite of the previously mentioned midstream challenges during the quarter, including a slowdown in infrastructure build-out affecting our ability to connect new wells. As a result, we turned in-line only eight wells during the quarter, which included a three well pad that was turned in-line at the end of the quarter, which is producing over 50 million cubic feet per day.

As discussed on the year-end call, our production growth for 2014 is weighted more toward the second half of the year. However, we do expect higher sequential growth in the second quarter, versus the flattish production profile we had discussed on the year-end call.

The second quarter has started off stronger, with Cabot averaging a product approximately 1.48 Bcf per day of gross production in the Marcellus, an increase of about 5% over the first quarter average. We plan to place approximately 15 wells on production during the second quarter, all of which will commence in either May or June.

Moving to the Eagle Ford, we also have good news to report in that area. We completed our first six well pad at the beginning of this month, and have been very impressed with the results. The six wells had an average completed lateral length lateral length of about 6,700 feet, and were completed with an average of 25 stages. The wells achieved an average peak 24 hour IP rate of 1,045 BOE per day, per well, with an 89% oil cut.

As a result of the continued drilling and completion efficiencies associated with our pad drilling efforts, we realized approximately $600,000 of cost savings per well. As a result of the improvements our team has made, both on the production side as well as the cost side, we have decided to add a third rig beginning in the third quarter.

The implied returns on our recent wells exceed 60%, at $90, which we believe warrants the additional capital allocation. The typical well in the Eagle Ford has an EUR of approximately 500,000 BOE, with a completed well cost of less than $7 million, based on approximately a 7,000-foot completed lateral.

While still early, the wells that we had just announced in the six well pad are outperforming this type-curve. The addition of a third rig is accretive to our Company's net asset value, and will add high-margin growth to our production profile. However, since the additional rig will be focused on multi-pads, and will be bringing it in in the third quarter, it is expected to have minimal impact on 2014 production, but should have meaningful add to our estimated oil production volumes in 2015. We recently added about 4,000 net acres to our Eagle Ford position, through our organic leasing efforts, and we will continue to actively lease in the area.

Now let me move to pricing; it's a mainstay now in a Cabot teleconference. In the press release, we mentioned, and indicated the Marcellus differential of $0.60 to $0.65 for January and February, and those levels held for the remainder of the first quarter. As we anticipated, which had been outlined in our recent investor presentations, the spread widened in April as certain winter contracts rolled off.

For the month of April, we have seen realized prices in the Marcellus before the impact of hedges of about $0.75 to $0.80 below the NYMEX. Much of that was driven by wider, first of month index prices on Tennessee and Leidy. However, the daily cash price for those pipes have improved during April compared to the last six months. We believe the stronger cash price can be possibly attributed to the increase demand from storage refill, which in turn, may be the reason we're seeing bids for term gas become more attractive.

Still early in season, so we will continue to monitor this dynamic as we move into the summer months. For any additional information on pricing points, and our firm capacity and firm sales, please see our current investor presentation on our website.

I would also be remiss if I failed to mention how the pricing dynamic should improve once Constitution pipeline is in service and we are able to deliver 500 million per day of our production to premium markets via the Iroquois System which head both North and South, and into the Tennessee 200 line which will move to Boston. This outlook continues to improve with the Atlantic Sunrise project scheduled for the second half of 2017. You may recall this pipeline will deliver 850 million cubic feet per day of our previously sold gas to multiple new markets, including new pricing locations.

On Constitution update, we continue to see additional progress, as we work towards final approval. You will recall that FERC issued a very favorable draft environmental impact statement back on February 12. A public comment period deadline was also established for April 7. And despite several parties requests for extensions, none were authorized by FERC. The FERC has established June 13 as the date for its planned issuance of the final environmental impact statement for the project.

The subsequent 90 day federal authorization decision deadline is set for September 11, with the final FERC order as early as mid-October of this year. In conjunction with the FERC process, Constitution filed for its New York DEC permit back in August of 2013. Constitution continues to fulfill its obligation to answer the data request to buy the New York DEC, as they process the application and work towards the issue of a final permit.

On the financial side, and subsequent to the quarter end, our lenders, under the credit facility, approved an increase in the Company's borrowing base from $2.3 billion to $3.1 billion, as part of an annual re-determination process. While commitments currently remain unchanged at $1.4 billion, the increase allows for increased flexibility for share repurchases, which will continue as an opportunistic decision based on relative valuations between the market and the internal view on intrinsic value. We have not, to date, this year mandate made any share repurchases.

The guidance, as it relates to our capital guidance, we have increased our capital program slightly to accommodate the third rig in the Eagle Ford, to $1.375 billion to $1.475 billion. But we also have tightened our production guidance range for the year to 530 to 585 Bcfe, and that does translate, and still implies a 35% production growth at midpoint. We remain confident that we will be able to continue to grow our volumes throughout the year and into next year.

In the Marcellus, we are currently producing about 1.5 Bcf per day of gross volumes, last month we added 70 million per day of additional Millennium capacity. And we will add an incremental 150 million per day of additional firm capacity on Millennium in September.

In addition to those volumes, we will be connecting our infrastructure directly to the largest LDC in the area beginning in the fourth quarter which will allow for an additional 200 million cubic feet per day of new capacity. Based on this incremental capacity, in addition to what we know about expansion projects like the Tennessee Rose Lake project, which will add about 250 million per day to the system, the recently announced open season on Millennium, for about 120 million per day, and the opportunity to increase our market shares on three major pipes in the area, we do remain confident that we can continue to grow our Marcellus production levels in 2014 and beyond.

Concurrently, we will be growing our high-margin oil production in the Eagle Ford also. As a result of our confidence, we are providing initial 2015 production guidance of 20% to 30%. This guidance is predicated on an average of 2 Bcf of daily gross Marcellus volumes through 2015, a level we are very comfortable with, and which may ultimately prove to be conservative. Additionally, this program would generate free cash flow in 2015, even if you do assume an all-in natural gas price realization of $350 and an oil price realization of $90.

As for 2016, assuming a Constitution in-service date of late 2015 or early 2016, we expect another year of top-tier growth for Cabot as we begin delivering 500 million cubic foot a day to new markets, in addition to the incremental volumes on Constitution, we will also be adding 125 million per day of new long-term firm sells, associated with Transco Southeast expansion project, and 50 million cubic foot per day of new capacity on Columbia's East side expansion, all of which are expected to be in service during the fourth quarter of next year.

In summary, while we've been very clear about 2014 and 2015, we'll be somewhat challenged as it relates to the pricing dynamics in the Marcellus, we are more confident than ever that the quality of our assets and the long-term value proposition for shareholders is very strong. Even with these near-term challenges, we will still provide top-tier production, and reserve growth while spending within cash flow. Again, not many companies can make that statement.

With over 20 years of inventory remaining in the best natural gas assets in the US, the sizable portfolio of new firm becoming available to us over the next couple of years, and improving position in the Eagle Ford, we believe the future of Cabot is as bright as it's ever been. Emily, with that, I'll be able to answer any questions.

Thank you.

(Operator Instructions).

Pearce Hammond, Simmons & Company.

Good morning. Dan, can you walk us through the puts and takes that you go through when considering whether to enter a long-term take-away agreement out of the Marcellus? For example, weighing the cost of a new Greenfield pipeline, and the optical advantage now for investors of seeing firm take-away capacity versus say, locking the Company into a disadvantage as pricing arrangement longer-term, especially if there might be excess take-away capacity out of the Marcellus later in the decade?

Well, I'll let Jeff cover some of that, Pearce.

As we've talked before, our evaluation and whether to enter into long-term firm sales, versus long-term transport contracts, versus participating in the pipeline for new take-away, all those factors are evaluated with each decision. I think early on we made a lot of good decisions on our long-term sales contracts, got way ahead of the game because the pricing was very favorable. I think in the last six months or so, we have slowed down considerably on entering into anything long-term that price disadvantage, as you called it.

As you know, we opted for a new pipeline expansion, coming out of Susquehanna County. That's the new 30 inch that will go down to the DC area and on to Cove Point. And as it worked out for us, from a netback perspective, that was a very, very favorable deal. And so each deal stands on its own merits.

The new transport we picked up on Millennium does a lot of good things for us, gets us to places that previously we had been unable to move our gas towards, higher pricing points. And so each case is different. But for the most part, it's evaluated along with all of our other options.

Thank you for that. My follow-up is, Dan, do you see any new horizontal potential on any of your legacy West Virginia acreage? That traditionally was targeting the Devonian Shale or the big line with the Brea formations? Then how much acreage do you have there?

In West Virginia, we have still approximately one million acres in West Virginia, and that's held by production. We had previously, in some of those shallow zones, Pearce, before we started developing in Marcellus. We had drilled several horizontal wells. And that opportunity still remains in West Virginia.

We have a evaluation process ongoing with our assets in West Virginia. We had recently permitted a well in the West Virginia area. And we will continue to look at enhancement opportunities on that acreage. So to answer your question, just succinctly, yes, we do think there are opportunities to drill horizontal wells in some of the areas in West Virginia.

Thank you very much.

Brian Singer, Goldman Sachs.

You talked to a number of the opportunities outside of Constitution where you're adding capacity having signed some midstream agreements, the Tennessee Rose Lake, the open season on Millennium, and then increase in market share from three major pipes among them. Can you provide a little bit more color on what the expected realized pricing is in transport costs associated with those non-Constitution related opportunities? And how widespread do you see additional opportunities from here?

I'll let Jeff make the overall comment, Brian but I will say that our price points are tied to different indices. And those indices are variable, if you will, out there on what the future realizations are going to be, but I'll let Jeff answer.

Okay, Brian. Again, with the comment that we made in the speech on Rose Lake was just another example of how there is new capacity opening up on Tennessee that allows for additional volumes to flow on that particular pipeline. So we didn't participate as a shipper, but we are selling gas to people who will participate as a shipper.

Number 2, I guess, is the other ancillary contracts that we have picked up in order to move gas from one basin to another. The pricing points all vary, transport costs all vary. For us, it's all about net-back, about assumptions we make on the pricing locations, and how that works to our best interest in getting the highest price for the product.

Each case is different. The Millennium capacity is fairly cheap as existing capacity. As you know expansion capacity, if they are on a pipe, is generally in the $0.50 to $0.60 range. But new pipe gets you a big advantage as another straw out of the Susquehanna County, so we look at all those factors when making those decisions.

As you look at future opportunities for signing midstream agreements, are you --where do you see those opportunities regionally? Do you see more opportunities to stick within the Northeast and get it to the markets that Constitution is tapping into, like New England, or do you see more opportunities emerging to go to the Gulf Coast and Southeast or Midwest? And it's really more a question on, are there still incremental opportunities in the Northeast, or are you really being forced to look more at the Gulf Coast?

I think there's still additional opportunities in the Northeast. As you know, look at our slide on the routes that Cabot Gas can reach in the markets, that it can reach. We intend to be very, very active in Canada at Waddington, it's in the far North part of the eastern part of the United States. We expect to supply a lot of gas in the Boston area and then coming South, New York, Jersey, Connecticut, all those areas, mid-Atlantic, the DC area we've been very active down in the Carolinas, into the Piedmont market, very active.

That's a huge market, that's a third of the country's population, and we think we can reach out to all those areas. And you know of course, we do have back haul transport that takes us back in Appalachian area, and to the Columbia pricing locations. So that's a lot of market. We think we have access, better access than most producers in Northeast PA, geographically we're situated very well.

I think the Southwest PA producers have opportunity in the Gulf Coast. We have not ruled out, though, and are talking with markets in the Gulf Coast about transportation paths and how our Marcellus gas can fit in with their plans.

Thanks. Dan, very quick last question can you comment on share repurchase?

Share repurchase, we had not been in the market yet, Brian. We have, as we've mentioned, we evaluated the noise in this very short period of time from our last conference call. We've been active in preparing a rather lengthy internal look at the future on all of our projects, opportunities, and sensitivities on accelerated projects, on price points sensitivities, on the macro market.

We've spent a great deal of internal time focused on that. We have our board meeting coming up. It's our intent to have some of this played out at our board meeting. But in the meantime, looking at the market, and looking at the swings in the market as I said earlier, the volatility is going to dissipate a little bit before we get into the market, but it is my expectation still, that we will be in the market at some point.

Charles Meade, Johnson Rice.

Dan, I was wondering if we could go back a bit to some of the prepared remarks and your comments about the assumptions you were making for the 2015 growth. I believe I heard you say that 22% growth rate is predicated on 2 Bcf gross a day in 2015. When I look at your growth, it seems like you probably hit that in like 1Q 2015 or 2Q 2015? Is that a fair guess, or are you thinking you're going to be 2 Bcf flat?

Well, no. I'd say that's a fair guess, and again it's an early guidance. We typically put our guidance out later in the year. We had enough questions and concern attached with what our confidence level is in our growth profile. We wanted to get out there. And as I mentioned in my comments, Charles, that we are entirely comfortable at this level of growth.

If you just look at our exit rate that we anticipate in 2014, and you carry that forward into 2015, you can get within that fairway of 20% to 30% growth in 2015. And that's why, added to the comments, that it may prove to be conservative at that level.

Right. And then also as you noted, you'd have free cash even at a 350 realized, and I think with all the, maybe another cut at Brian Singer's question, you've talked a bit about what your posture is, and this may be too far down the road, but you talked a bit about what your posture is right now. But as you go into a year from now, or even nine months from now, when Constitution, the pipes in the ground, and you get more confidence on what your 2016 growth is going to look like, that's where you're really going to have --

Some opportunities.

Yes, and so is that the timeframe when you think that you're doing of this internal work right now, is, is it really the time to pounce is going to be about 12 months from now?

Well the --and the reason for the extended look and being more granular at our extended look, was to stack up all of the opportunities that we had in front of us, and that we have in front of us, and to look at the planning that we want to do right now, and moving forward. To one, be able to have the right staffing, two, to be able to plan for the right services and personnel to be able to assure program execution, to be able to achieve those levels.

We know the assets can deliver them. We are entirely comfortable with our asset pool and the results of our wells, and our consistency of cost in drilling wells. But we do want to put together the whole program, in a, let's say a more detailed fashion than we have in the past. And we're excited about when we stack up all these opportunities and it looks at the new markets that we're going to be able to access, and making some of the assumptions that you do on price points, that we're getting to with our new gas, it's a robust program.

Thanks for those added comments, Dan.

Joe Allman, JPMorgan.

Dan, are you expecting in 2015 that you will have quarterly growth through 2015? Or are you not expecting it at this point? If that is your expectation, what gives you the confidence in terms, of aren't the pipes full? How can you actually move the gas?

I think you've seen each --and I'll pitch it to Jeff on after I make a comment, but I think you've seen in each, just about each quarterly conference call we come out and announced some type of capacity additions that we've added to the plan. And we think we'll be able to continue to do that.

In regard to just keeping the production flat, and what it is quarterly, right now Joe, our expectation is 2 Bcf and whether we go from 1.8, 1.9 Bcf-a-day to a 2.1 Bcf-a-day to the end of the of the year, I'm comfortable at saying the average is going to be 2 Bcf plus. And how it rolls through the year is going to be sequential growth, but I don't have it that granular at this time.

Yes, Joe, this is Jeff. I think two parts to your question. One, if I understood it correctly, shorter-term versus longer-term, in shorter-term we tried to lay out in the speech that we have picked up additional capacity that was existing capacity on Millennium, 70,000 last month, and incremental 150 coming up. We laid out a plan that actually connects our infrastructure in Pennsylvania to the state's largest utility up there, and we have already entered into sales agreements with them.

There's additional capacity coming up on all the pipes that we operate on. So shorter-term, when I say next 18 months, we're not in the same camp as what you refer to as, aren't all the pipes full? We are not in that camp.

Longer-term is most definitely Constitution, a big 30-inch pipe that is going to take us to go to new markets or three new markets, two new interstates. And Central Pin part of Atlantic Sunrise, another big 30-inch pipe coming out of our operating area. So we feel real good about years three, four, and five from now, that we'll be able to grow.

Have you guys put in some cushion for any shut-ins or any down time? I think last year you had some shut-ins?

We typically always risk our production profile as we do with our EUR's and as we also put in a little bit of contingency in our AFEs.

Got you. Also, separate question, this might be for Scott, the DD&A showed a nice drop from the fourth quarter to the first quarter on an Mcfe basis. What should we read from that nice drop in DD&A?

That's the year-end true-up, Joe, from all the final year-end reserve report. When our property accountants go through and repopulate the database and that's the rate going forward now. And that's what also adjusted the top-end of the guidance down.

Great. Very helpful. Thank you.

Doug Leggate, Bank of America Merrill Lynch.

I wonder if I could change topics a wee bit down onto the Eagle Ford. Obviously you're adding regular now. But I'm curious as to how you're seeing the backlog, the location count. And ultimately how more aggressive do you think you can be over time, in terms of acreage opportunities, and ultimately continuing to shift the balance of your spending towards that area? I've got a quick up quick follow-up on the Marcellus, please.

Doug, again as you saw the numbers, as we reported, they're good numbers they are meeting or exceeding our expectations to continue to allocate capital. We feel comfortable allocating the third rig. We feel comfortable being able to acquire additional acreage to bolt-on.

Our location count in the Eagle Ford is probably 500, 600 locations or so, and that certainly includes our Presidio area also. So once we get our arms around this third rig, I think it's intuitive to think that we would also look at an expanded program, and possibly to a fourth rig, also in the Eagle Ford, particularly as we continue to acquire acreage.

So how should we think about the priority for allocating cash and thinking Marcellus, Eagle Ford and buybacks, if you put those three in some kind of order, maybe acreage acquisitions added in there as well?

Well, on the capital allocation to the Marcellus, we have put together a six rig program. And basically a 2-rig or 2-crew completion pumping services. And we're rolling that forward with that program. So from a bottoms-up build, that gives us a pretty good handle in our cost consistency there, it gives us a good of handle on the amount of capital necessary to allocate to achieve that program.

When you look at the Eagle Ford, and we go to a three well program, it's a fairly easy number to get to also on what we'd be allocating. And from a priority standpoint, our operations program is where we're going to be allocating a program as opposed to a share buyback.

But when you look at going to a split, we'll probably be again, 65% plus or minus to the Marcellus in 2014 as a year-end guesstimate. And the rest will be allocated to the Eagle Ford. And some of the other projects that we have on the slate that are more exploratory in nature.

Going into our 2015 program, again, we haven't put the capital allocation out there right yet, but going into 2015 program, I would think that our capital allocation would go into a 55% plus or minus 60% plus or minus in the Marcellus, and the remainder going towards the Eagle Ford and the additional exploratory projects, or exportation projects that we're working on.

I don't suppose you'd like to elaborate on any of those additional projects at this point Dan?

Nice try, Doug.

Thanks, guys. Appreciate it.

Gil Yang, DISCERN.

I was just wondering, in terms of the visibility for capacity additions to get to that two Bcf, how far along are you in negotiations, what's the visibility on those specific projects, do have them in mind, they're on checklist, or is it more advanced than that, or less advanced than that, in terms of your targeting for those incremental adds?

Sure, Gill, I think for the most part, we're close. And it will take a few pieces of capacity. We're working with other shippers on, just to make sure, and get in that comfort zone that we have exactly what we need. But going forward, it looks very favorable. We're not concerned about not flowing that amount of gas.

Great, okay. And then second question on the Eagle Ford. The counties of the six-well pads is on, and can you count on that and what --those are some of the best wells you've drilled, at least on a test basis. Would you assign that to the pad drilling and pat fracking or is there something different going on, in either the geology or the completion design?

Majority of our acreage is in Frio County. We have the extended lateral, as far as a pad, one, it was the largest number of wells we drilled from one pad. On average, for wells located in close proximity, it is certainly the longest laterals that we have used.

And the density or spacing of the frac stages came down a little bit, also from our average of our prior wells. In fact, we will probably have a little bit further reduction in our frac stage spacing as we roll forward to evaluate efficiency gains that we might be able to drive from that.

What was the stage spacing that you -- I guess I can figure it out, because you use 25 stages, so that's--

It's a little over 250.

What was it prior to that?

We were probably closer to 275 to 300.

Okay, great. Thank you very much, Dan.

Subash Chandra, Jefferies.

I was trying to understand the size of the term market that was in your initial discussion that might be reflecting storage refill demand, and how predictable that term market might be, how it fits into your growth profile, if at all?

Yes, this is Jeff again. I think the comment we made about the storage refill was just to indicate how strong daily cash prices have been up in the northeastern part of the Marcellus. Comparably speaking, cash has been very strong for the last month or so. And we're expecting the cash markets to stay strong throughout the storage refill period. And that has led to an improvement in the term market being the summer market, maybe the one-year market, maybe the one out in the next couple years for basis differentials inside the term contracts.

As little as six weeks, eight weeks ago, the [summer] on certain price is trading $1.75 under NYMEX for example. Today, that's probably $1.00 under NYMEX. So there has been strength in the marketplace for the term business aspect, and it looks like it's going to continue.

I guess put another way, the spot market slash [interruptible's], how big is that, and how can you take advantage of that, on sort of an ongoing basis? For instance, these cash sales, can you go above and beyond the firm, for instance. I think everyone looks at the presentation, they see the firm and they just sort of expect that you can't produce a single molecule over on top of that.

There's a Company yesterday, whose strategy is not to tie-up firm, because they believe they're in different parts of the play, but they believe that the Marcellus will be over infrastructure within 18 months. They don't want to lock up that way. So how do we get that confidence that there is that, a cash market or some sort of interruptible market beyond the firm on page 5 of your presentation?

A couple points on that. I think there is a chance that infrastructure could be over-built in 18 months or two years, I would agree with that in both the Southwest PA and Northeast PA. We have taken an approach where we have tied up certain volumes of our gas, and again, this is on the website presentation, certain volumes of our gas, long-term contracts, and those long-term contracts, those customers are using their firm transport, their firm take-away to take that gas to their city gates.

The second approach was to purchase firm transport, and again, those numbers are available to you on the presentation. Those volumes are --we control and we move those molecules to certain locations for better pricing, of course.

And then the third aspect of our marketing approach has been to enter in the spot sales. Those are typically 30-day sales, summer sales, April through October, winter period sales, November through March. Day gas, cash sales, and I don't think we're unlike a lot of producers. We have a portfolio of options, and that's our approach to marketing each month.

The producer that you mentioned, I've heard producers are --some producers say, simply we will produce our gas, in the amount of firm we own. We've taken a little different approach to that. We're looking at all aspects of the market opportunities that are sitting there in front of us. And I think the most part, we have a little advantage, and that we're delivering gas to three major interstate pipelines. We're not married to one.

And the infrastructure that we designed gives us flexibility to move gas between those pipelines based on pricing, and pipeline pressures, and with the additional Constitution, it's going to take us, of course, to Interstate's number 4 and 5, and then Atlantic Sunrise to Interstate six and seven. So having seven interstate markets, and again, attached to one of the largest, or the largest utility in the state gives us a lot more options and opportunities.

Okay. If I could ask one last question on the matter, I'll promise to jump off. So the three pads out there, long-term to contracts with those with firm, purchased your own firm, and spot, is there a way to quantify, perhaps on an annual basis, how big that spot market is? For you specifically or for the sector?

That would be difficult and I'll explain why. I think the buyers of gas, both industrials and utilities, they're all different. They all take different approaches and they all have different buying habits, purchasing habits. And when you throw in the mix of power plants, then it really gets confusing as to who's using what capacity on what day to get to what market.

For the most part, we have very consistent day sales. We know we have markets that count on us for gas. And I think other producers take the same approach, but to try to quantify who's using what on what date during what period of time during the year would be difficult.

Okay, understood. Thank you very much.

Jeffrey Campbell, Tuohy Brothers Investment.

Dan, it appears it's taking at least three months to get a new rig running in the Eagle Ford. Is that based on internal capital logistics or is that based on rig availability?

That's based on just getting the locations in order, the permits squared, and our services all lined out.

Okay.

But it's not because of rig availability.

Okay. And thinking forward on that locations point, with the addition of the third rig, is the strategy to execute the longer lateral closer spacing method throughout the aerial extent of your acreage, or are you concentrating in a core area?

No. Our wells are fairly scattered throughout our area. So the intent is to continue to try to capture the efficiencies by multi-pad, longer laterals, frac stage density, and we think that we're gaining --making progress on that.

Okay. And my last question --

That will be throughout our acreage.

That was what I wanted to hear. My last question is assuming you've reached free cash flow in 2015, will you seek to maintain free cash flow going forward from that point?

Well, I think by virtue of our growth expectations, I definitely think that we will.

Okay. Great. Thanks very much.

Thank you.

Bob Brackett, Bernstein.

Quick question about Marcellus inventory. Can you give us an idea of how many wells you have drilled and completed, how many wells completed waiting tie-in, and maybe, even if you didn't have midstream constraints, what's your flows could look like?

Okay. On the well site, we have about 22 wells that are waiting on pipeline. We have five wells that we are currently completing. And we have 24 wells that are waiting on completion. So we have a pretty good backlog right now. And again, we knew that we would be building up quite a backlog and at this period of time. And we are, from this point forward, we're moving, going to be moving through those and working those numbers down.

And what could your system run if there wasn't a midstream constraint?

I don't know. I can't think of a day, when I look at my daily drilling report, I can't think of a day that we have not seen a compressor down, or de-high down, or something like that. And that's just the nature of the beast. And just a lot of moving parts, in a large gathering infrastructure system like that.

So it would be rate speculation, but I'm sure it would be, we'd hit -- we've hit over 1.5 Bcf. I think the record was 1.538 or something close to that. I'm sure if we had things just humming along, and we had the compressors tuned up the way we want them, we'd be well over 1.6 Bcf a day.

Thank you.

Jack Aydin, KeyBanc Capital Markets.

How many frac stages do you have waiting? And then I'm looking --you're going to drill about 155 to 170 wells. A lot of those coming, maybe in the second half of the year. If you --if I run the numbers in a way, your 2015 guidance, granted has some upside, but it looks like quite conservative maybe. Could you --

Yes. Well, we have again, we have, as I mentioned, the number of wells that we are either completing, waiting on pipeline, or waiting on completion, it's 51 wells. And that's probably over 1400 stages, Jack, right now, that we have in the queue.

So the good news is, that we've been able to continue our production profile. We've been able to sequentially grow those slightly, we've been able to sequentially grow our production from last quarter, and we did it with only bringing on --with eight wells that we brought on for the quarter.

We're going to double the amount of wells that we bring on in the second quarter, and we will continue to increase the number of wells that we plan on bringing on in the third quarter and fourth quarter. From what we realized in the first and second quarter.

So we are going to go into 2015 in very good shape as far as what we think our production profile will be, and what we plan on still having remaining in inventory. We are in good shape. I feel very good about it. And because of our efficiencies that we've been able to gain with the drill time, and continue to doing good along those lines, that's why we made the decision to only have six rigs versus having to increase the number of rigs there.

Second question, you have been permitting West Virginia and with Guarantee. What you really looking for there? And are you looking for the Point Pleasant in that potential test, or what other things you see that you have there?

Bottom line, Jack, we're looking for oil and gas.

Okay.

We are extending a look at the play South, where the drilling has been. And we think our fairway is in the volatile window. And we think that we have an opportunity there. So that is the section --one of the sections that we're looking at.

Thank you.

David Beard, Iberia.

Could you give us a sense in your 2015 production guidance, what your assumptions are for transportation, or maybe just in general, what you're thinking about the differentials as we roll through next year?

Well, the differentials are a hard number to get. We think that the differential is going to be somewhat similar to what we're experiencing today. On our production guidance, we've had some discussion on the capacity that we now maintain firm transportation, firms sales, and the additional capacity that we expect to add to our inventory.

As Jeff mentioned, to get to that two Bcf level, it's probably 100 million, 150 million of additional work, or capacity, or sales, that we would realize, in addition to our firm that would get us to the two Bcf mark.

Great. Thank you.

Matt Portillo, PPH.

Just a quick question, wanted to clarify, heard a lot a great detail on, kind of incremental capacity you guys have signed up, or are looking to sign up. Could you just put that into context relative to the presentation you guys had out a couple months ago, where you laid out your 2015 firm capacity? I think about 1.1 Bcf a day. Could you give some color on how much that's changed on a relative basis and where we sit at the moment?

Sure, Matt, this is Jeff. It definitely has improved on the --the numbers have improved somewhat on --from that presentation. I wouldn't say they've improved a great deal. We have a lot of deals that were working on, that were close to wrapping up. We've had some opportunities that we know that is out there, that we're close to wrapping up. Probably the biggest number to add to the slide is our new capacity into the utility there in Northeast PA. And that will be added to that chart at some point.

Great, and then as we think about your 2015 guidance, could you give us some rough color on how you guys think about --I know you've laid out Leidy Zone 4 previously, it's about 45% or so percent of your 2014 production in terms of exposure there. How does that look currently in 2015, just from a rough estimate perspective?

We can get back to you on that on exact percentage, but we're going to be growing the production, and so that number will probably increase slightly. But I'll have to get back and I'm sure you'll see it, Matt, in one of our future presentations. Once we get more granular on our 2015 guidance.

Perfect. Last question for me, was hoping you could talk a little bit about the organic leasing opportunity you see today within the Eagle Ford. Then any appetite in regards to M&A in the basin? Thank you.

Organic leasing, it is what it is. We continue to talk to owners of the unleased acreage out there. And we think there's an opportunity to pick up additional acreage.

And as far as M&A activity in the basin, I think there are some opportunities to pick up some small professionals that own acreage out there. And if the opportunity arises, we'd look at it. Some of the pricing that we've seen in the M&A side of the business has been fairly robust. And we think the capital efficiency of organic approach is more prudent for us at this stage.

Thank you very much.

Wayne Cooperman, Cobalt Capital.

I'm sure that this has been asked in 100 ways, but I'm just wondering --people are really worried about pricing. I wonder at what price do you have to --do you see where you cut back production, and just wait until you get better pricing with better takeaway? I don't know if I'm phrasing that question in a way that I can get an answer.

Well, Wayne, it is hard to pick a price that you say that you're going to just shut-in production. Particularly with the yield that we get from a fairly low price point. But I'm not going to state just a price that we're going to shut-in.

But if the market looks like it's behaving in a way that would be prudent for us to shut-in gas today and sell it near-term, then we look at that. But we don't have any plans right now to shut-in any large volumes of gas with the market that we see out in front of us.

Maybe let me try to rephrase that a little differently than. We all know the gas is there. You have the best rock in the country probably. And you've got a takeaway capacity right now that's going to get alleviated, and therefore the differentials that you're seeing now should dissipate over time.

Isn't there --don't you earn more money by producing less gas now, selling at a low price, and just producing more gas in two years when you're going to get much closer to Henry Hub?

I think there is an equation you can run, Wayne, that would get you to that point. But at this stage, again, our realization was 374. And for this last quarter, we are delivering a good return. We're putting that capital to use that's delivering, again, a return profile. For example, adding the third rig in the Eagle Ford that is generating a nice return with those investor dollars.

But I do understand your question. And certainly it's an equation that we can run. For example, if we were getting close to flipping the switch on Constitution and it was just a significant blow out, and somebody wanted us to move a gas for a buck, we're not going to move it for a buck. We'll wait to open the capacity of Constitution and start selling our gas into a different market that would not be realizing those prices. So I understand your question. And there's merit to it.

And is there --just is there some --like limiting factor to how low a price can go in your market? Or there's really nothing that stopping from trading at $1.00 or $2.00 in a bad part of the market.

Well, I think if you look at --all of the producers out there, we're not the only one selling into these markets. When you look at the amount of gas that's going into Tennessee or going into Leidy, there's gases from a lot of different price points, not just up in the box, up in Northeast PA, but there's other gas flowing into those pipes to saturate the market. So I think there is a price out there that industry would say, we're not going to move our gas for that. It's more valuable than that and we're not going to move it. So there's that price point.

What it is exactly, $1.00 or $1.50, I don't know where it might be, $2.00. But there's certainly a price point. I think a number of producers would say we're just not going to move our gas at that price.

All right. Thanks a lot. I'm sure everybody's got the same basic question.

Yes, thank you, Wayne.

Joe Allman, JPMorgan.

Dan, thinking about your ability to take on some extra capacity. If there's extra capacity in the systems, why are the differentials around negative $0.70? Just trying to get my head around that.

Well, I tried to get my head around it also. And one of the things that we're looking at -- I'll pitch this to Jeff, that digs deeper than I, but when you look at some of the differentials and you see how the indices are established, you have really, a very few contracts that are capturing volumes out there, that are setting the index, and what's supposedly two parties, a buyer and seller willing to move gas for, I question the differentials, and particularly the number of contracts that are steering a large volume of gas.

We're looking into the transparency of all of the transactions. So right now, being able to have access to a buyer and a seller, from my understanding, at this stage of my look, is that those are confidential parties. But I'm looking at it, to try to understand it a little bit more in detail also.

Yes, Joe. I think the improvement we've seen in pricing has --a couple factors that have influenced it. One has been the winter. There's good price realizations going on in the cash market as we mentioned before. I think the demand and the actual people who burn the gas, at some point, they come into the equation, yes, there is excess capacity up there, but is there, just how much more incremental demand is there in certain parts of the year?

So I realize that we expect an improvement in the differentials when we had a good winter. They did improve all the way up to a flat Henry Hub type number. And I think we're struggling to understand completely the dynamics of that.

One of the approaches for us has been to make sure that, not only do we have firm transport, but firm sales, and particularly, our last deal with Code Point and Washington Gas, to make sure that we actually have someone that burns the gas, having a 850 million a day, 15-year, 20-year contract for people that do burn it, was very important to us.

So I agree with you. I don't understand exactly the dynamics that would cause a $0.70 differential at this point. But it has been a big improvement over the last 60 days.

So how much of the incremental capacity do you expect to take over the next several months? How much of that is actually new capacity and how much of it is, you actually just taking someone else's capacity? So for example, that 150 million a day from Millennium in September, like --that's new capacity?

No. That was existing capacity, it just hadn't been sold yet, excuse me, just hadn't been bought yet. And we bought it. The UGI, excuse me, the utility sales are new, incremental to us. I think there's existing capacity in every pipe.

And the way we work the system and the way the system works is, the capacity we pick up could be one-year duration, two years, five years in duration, could be 15 years with Evergreen provisions. It could come from someone who bought it and is just red ink to them, or it could be expansion capacity.

There's a lot of deals and transactions made in the secondary capacity release market. And we continually work that, and we do take capacity in short-term releases as well. When they net us back our prices. And so, there's again, a lot of capacity in those pipes. Sometimes it takes you to places you don't want to go. Sometimes it doesn't start where you wanted to start.

So for all the producers in the Marcellus as a whole, there is a constant jockeying around of positions on capacities to make sure that gas flows every day, and that backs (inaudible) are high as they can be.

So is the only new capacity that you mentioned of all the different agreements that you're entering into, is the only new one, the 120 million a day of open season that Millennium's having?

Okay. So that capacity, when you say it's new, it's new to the marketplace, it's existing in the pipe. It's a confusing terms. We're out there, we've put a bid in to take some of that capacity. We didn't want it all because some of it doesn't do us any good.

And likewise, when Transco went out last month with 200,000 a day of capacity for a shorter term, I think it was a nine month term, we took part of that capacity. It's an ongoing process. I think all the pipes use their resources to try to increase their throughput.

They're constantly looking at ways to add capacity to the system, and as contracts get taken, it actually opens up. It could open up space for gas to move in different directions. So it's just something that all the producers and shippers and markets face on a day-to-day basis.

Got you. Very helpful. Thank you.

And this concludes our question-and-answer session. I'd like to turn the conference back over to Mr. Dinges for any closing remarks.

I appreciate everybody's interest. Obviously the conversations regarding the movement of gas and our ability to grow is on everybody's mind. I can assure you we're confident that we would be able to deliver within our guidance point. Otherwise, we would not put those open guidance points out.

But when you look at what we have to be able to deliver in the future, we're going to --comfortably deliver top-tier production growth, not only in the next few years, but moving out, we'll also have reserve growth that will be very robust. We'll do it in a free cash flow environment.

And that gives us, certainly confident, that we're going to be able to continue to enhance shareholder value on out into the future. And it's certainly should give the shareholders confidence that the asset package we have will be able to deliver that value. So again, thanks for the questions. And we will see you next quarter.

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