Good morning. Welcome to the Cabot Oil & Gas Corporation First Quarter 2014 Earnings Conference Call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on a touch-tone phone. To withdraw your question, please press star and then two. 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. 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 would 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. Those are the production during the first quarter averaged 1,332 million cubic foot 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-Con 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 to 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, I do think worth repeating, during the first week of this month, we reached a milestone in the field of one TCF 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 recognized the productivity of these unique assets. There'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, and that's in the Marcellus and the Eagle Ford program. In the Marcellus, we averaged 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 foot per day. As discussed on the year-end call, our production growth for 2014 is weighted more to 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 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 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. A 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 an end 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 on a Cabot teleconference. In the press release, we mentioned and indicated the Marcellus differential of $0.60-$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-the-month index prices on Tennessee and Leidy. 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 increased demand from storage refill, which in turn may be the reason we're seeing bids for term gas become more attractive. Still early in the injection 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 fail 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 will head both north and south and into the Tennessee Gas Pipeline Zone 4 200 Leg, 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 new pipeline will deliver 850 million cubic foot 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 12th. A public comment period deadline was also established for April 7th, and despite several parties' requests for extensions, none were authorized by FERC. The FERC has established June 13th 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 11th, 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 State Department of Environmental Conservation permit back in August of 2013. Constitution continues to fulfill its obligation to answer the data request by the New York State Department of Environmental Conservation 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-$3.1 billion as part of an annual redetermination process. While the 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 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-$1.475 billion. We also have tightened our production guidance range for the year to 530-585 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 foot 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%-30%. This guidance is predicated on an average of two Bcf of daily gross Marcellus volumes through 2015, a level we are very comfortable with, and which may ultimately prove to be conservative.
This program would generate free cash flow in 2015, even if you do assume an all-in natural gas price realization of $3.50 and an oil price realization of $90. As for 2016, assuming 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 sales 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.
While we've been very clear that 2014 and 2015 will be somewhat challenged as it relates to the pricing dynamics in the Marcellus, we're 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 U.S., a 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. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star and then two. At this time, we'll pause momentarily to assemble our roster. Our first question comes from Pearce Hammond of Simmons & Company. Please go ahead.
Good morning.
Hi, Pearce.
Dan, can you walk us through the puts and takes that you go through when considering whether to enter into a long-term takeaway 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 takeaway capacity versus, say, locking the company into a disadvantageous pricing arrangement longer term, especially if there might be excess takeaway capacity out of the Marcellus later in the decade.
Well, I'll let Jeff cover some of that, Pearce.
Okay, Pearce. As we've talked before, our evaluation of whether to enter into long-term firm sales versus long-term transport contracts versus participating in a pipeline for new takeaway, 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 has a 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 D.C. area and on to Cove Point. As it worked out for us from a net back perspective, that was a very, very favorable deal.
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. 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 Lime or the Berea formations? How much acreage do you have there?
Well, in West Virginia, we have still approximately 1 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 them ourselves, we had drilled several horizontal wells, and that opportunity still remains in West Virginia. We have an evaluation process ongoing with our assets in West Virginia. We had recently permitted a well in the West Virginia area, and we'll continue to look at enhancement opportunities on that acreage. 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.
Thank you, Pearce.
Our next question is from Brian of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Hey, Brian.
You talked to a number of the opportunities outside of Constitution, where you're adding capacity, having signed some midstream agreements, the Tennessee Gas Rose Lake, the Open Season on Millennium Pipeline, then the increase in market shares on three major pipes among them. Can you provide a little bit more color on what the expected realized pricing is and transport costs associated with those non-Constitution-related opportunities? How widespread do you see additional opportunities from here?
I'll let Jeff make the overall comment, Brian, I will say that our price points are tied to different indices. Those indices are variable, if you will, out there on what the future realizations are going to be. I'll let Jeff answer.
Okay, Brian. To begin with, the comment that we made in the speech on Rose Lake was just another example of how there's new capacity opening up on Tennessee that allows for additional volumes to flow on that particular pipeline. We didn't participate as a shipper, but we are selling gas to people who will participate as a shipper. Number two, 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. It's about the assumptions that we make on the pricing locations and how that works to our best interest in getting the highest price for product. Each case is different. The Millennium capacity is fairly cheap. It's existing capacity.
As you know, expansion capacity up there on new pipe is generally in the $0.50-$0.60 range. New pipe gets you a big advantage as another straw out of the Susquehanna County. We look at all those factors when making those decisions.
As you look at, and this is probably a follow-up for Jeff, as you look at future opportunities for signing midstream agreements, 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? Do you see more opportunities emerging to go to the Gulf Coast and the Southeast or Midwest? 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?
No, I think there's still additional opportunities in the Northeast. As you know, if you look at our slide on the routes that Cabot Gas can reach and the markets that it can reach, we intend to be very active in Canada at Waddington. It's in the far north part of the eastern part of the U.S. We expect to supply a lot of gas into the Boston area and then coming south, New York, New Jersey, Connecticut, all those areas. Mid-Atlantic, the D.C. 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, we think we can reach out to all those areas. You know, of course, we do have backhaul transport that takes us back in the Appalachian area into the Columbia pricing locations.
That's a lot of market. We think we have 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?
The share repurchase, we have 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 point 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. In the meantime, looking at the market and looking at the swings in the market, as I'd said earlier, that the volatility is going to dissipate a little bit before we get into the market. It is my expectation still that we will be in the market at some point.
Thank you.
Our next question is from Charles Meade of Johnson Rice. Please go ahead.
Good morning, gentlemen. Thanks for taking my question. Dan, I was wondering if we could go back a bit to some of your prepared remarks and your comments about the assumptions you were making for the 2015 growth. I believe I heard you say that that 20%-30% 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 1Q 2015 or maybe 2Q 2015. Is that a fair guess, or are you thinking that you're going to be 2 Bcf flat?
Well, no, that's a fair guess. Again, it's an early guidance. We typically put our guidance out later in the year. We've had enough questions and concern attached with what our confidence level is in our growth profile. We wanted to get it 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, you carry that forward into 2015, you can get within that fairway of 20%-30% growth in 2015. That's why I added to the comments that it may prove to be conservative at that level.
Right. Then, also as you noted, you'd have free cash even at a $3.50 realize. I think with 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've 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 pipe's in the ground, and you get more confidence in what your 2016 growth is going to look like, that's where you're really going to have
Some opportunities.
Yeah. Is that the timeframe when you think that when you're doing all this internal work right now, is it really the time to pounce is going to be about 12 months from now?
Well, 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're entirely comfortable with our asset pool and the results of our wells and our consistency of cost in drilling wells. We do want to put together the whole program in a, let's say, a more detailed fashion than we have in the past.
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.
Thanks, Charles.
Our next question is from Joe Allman of JPMorgan. Please go ahead.
Yeah, thank you. Good morning, everybody. Dan, are you expecting in 2015 that you will have quarterly growth through 2015? Are you not expecting it at this point? If that is your expectation, just give us what gives you the confidence in terms of aren't the pipes full? How can you actually move the gas?
Well, I think you've seen each, I'll pitch it to Jeff after I make a comment, I think you've seen in just about each quarterly conference call, we come out and announce some type of capacity additions that we've added to the plan. 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, whether we go from a 1.8, 1.9 Bcf a day to a 2.1 Bcf a day to the end of the year, I'm comfortable at saying the average is going to be 2 Bcf plus, how it rolls through the year is going to be sequential growth, I don't have it that granular at this time. Jeff, you want to make-
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, we have already entered into sales agreements with them. There's additional capacity coming up on all the pipes that we operate on. 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're not in that camp.
Longer term is most definitely Constitution, a big 30-inch pipe that going to take us to two new markets or three new markets, two new interstates, Central Penn, part of Atlantic Sunrise, another big 30-inch pipe coming out of our operating area. 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 downtime? I think last year you had some shut-ins.
Yeah. We typically always risk our production profile, as we do with our EURs, as we also put in a little bit of contingency in our AFEs.
Got you. Hey, Scott, 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?
Well, 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. That's why we also adjusted the top end of the guidance down.
Okay, great. Very helpful. Thank you.
Thanks, Joe.
Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Thanks. I wonder if I could change topics just a wee bit, Dan, onto the Eagle Ford. Obviously, you're adding a rig there now, but I'm just 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 follow-up on the Marcellus, please.
Okay, Doug. Yeah. Again, as you saw the numbers and 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. 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.
How should we think about the priority for allocating cash? I'm 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 two-rig or two-crew completion pumping services, and we're rolling that forward with that program. From a bottoms up build, that gives us a pretty good handle in our cost consistency there. It gives us a good 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, that's a fairly easy number to get to also on what we'd be allocating. From a priority standpoint, our operations program is where we're going to be allocating a program as opposed to a share buyback. 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.
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 the 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, Don?
Nice try, Doug.
Okay. Thanks, guys. Appreciate it.
Appreciate it.
Our next question is from Gil Yang of DISCERN. Please go ahead.
Good morning. I was just wondering, in terms of the visibility for capacity additions to get to that 2 BCFs, how far along are you in negotiations, or what's the visibility on those specific projects? Do you have them in mind? They're on a checklist? Is it more advanced than that or less advanced than that in terms of your targeting for those incremental adds?
Sure, Gil. I think for the most part, we're close. 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. Going forward, it looks very favorable. We're not concerned about not flowing that amount of gas.
Great. Okay. Second question on the Eagle Ford, the counties that this 6-well pad was on, can you comment on that? 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 pad fracking, or is there something different going on in either the geology or the completion design that
Yeah. 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've drilled from one pad. On average, for wells located in close proximity, it is certainly the longest laterals that we have used. The density or spacing of the frack 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 frack stage spacing as we roll forward to evaluate the efficiency gains that we might be able to derive from that.
What was the stage spacing that you I guess I can figure it out because you used 25 stages, that's the way?
Yeah, it's a little over 250.
What was it prior to that?
We were probably closer to 275-300.
Okay, great. Thank you very much, Dan.
Thanks, Gil.
Our next question is from Subash Chandra of Jefferies. Please go ahead.
Yeah, thanks. Good morning. 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 quote 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 Northeast part of the Marcellus. Comparatively speaking, cash has been very strong for the last month or so, we're expecting the cash market to stay strong throughout the storage refill period. That has led to an improvement in the term market, being the summer market, maybe the one-year market, maybe going out in the next couple of years for basis differentials in signing up term contracts. As little as six weeks, eight weeks ago, the summer on certain prices trading $1.75 under NYMEX, for example. Today, that's probably $1 under NYMEX. There has been strength in the marketplace for the term business aspect, and it looks like it's going to continue.
Well, I guess, put another way, the spot market/interruptibles, how big is that? How can you take advantage of that on a sort of ongoing basis? For instance, these cash sales, can you grow above and beyond the firm? 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 was a company yesterday whose strategy is not to tie up firm because they believe they're in a different part of the play, but they believe that the Marcellus will be over-infrastructured within 18 months. They don't want to lock up that way. How do we sort of get that confidence that there is a cash market or some sort of interruptible market beyond the firm on page five of your presentation?
Okay, a couple of points on that. I think there is a chance that infrastructure could be overbuilt in 18 months or two years. I would agree with that in both Southwest PA and Northeast PA. We have taken an approach where we have tied up certain volumes of our gas, this is again on the website presentation. Certain volumes of our gas into long-term contracts, those long-term contracts, those customers are using their firm transport, their firm takeaway to take that gas to their city gates. The second approach was to purchase firm transport, again, those numbers are available to you on the presentation. Those volumes we control, and we move those molecules to certain locations for better pricing, of course. 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. 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, or I've heard producers or some producers say simply, "We will produce our gas 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. I think for the most part, we have a little advantage in that we're delivering gas to three major interstate pipelines. We're not married to one. The infrastructure that we've designed gives us flexibility to move gas between those pipelines based on pricing and pipeline pressures.
With the additional Constitution, it's going to take us, of course, to Interstates 4 and 5, then Atlantic Sunrise to Interstate 6 and 7. Having seven interstate markets and, again, attached to one of the largest utilities, 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, and I'll promise to jump off. The three paths there, long-term to contracts to those with firm, purchase your own firm, and spot. Is there a way to quantify, perhaps on 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 to it and all have different buying habits, purchasing habits. When you throw in the mix the 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 have markets that count on us for gas. I think other producers take the same approach. To try to quantify who's using what on what day during what period of time during the years would be difficult.
Okay, understood. Thank you very much.
Thank you.
Our next question is from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.
Good morning.
Morning.
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 is based on us just getting the locations in order, the permits squared, and our services all lined out.
Okay.
It is not because of rig availability.
Okay. 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 on a core area?
Our wells are fairly scattered throughout our area, the intent is to continue to try to capture the efficiencies by multi-pad, longer laterals, frac stage density, and we think that we are making progress on that.
Okay. My last question is.
That'll be throughout our acreage.
Okay. Yeah, that was what I wanted to hear. My last question is, assuming you reach 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.
Our next question is from Bob Brackett of Bernstein. Please go ahead.
Hi, good morning. A quick question about Marcellus inventory. Can you give us an idea of how many wells you have drilled uncompleted, how many wells completed waiting tie-in, and maybe even if you didn't have midstream constraints, what your flows could look like?
Yeah. Okay. On the well side, we have about 22 wells that are waiting on a pipeline. We have five wells that we are currently completing, and we have 24 wells that are waiting on completion. We have a pretty good backlog right now. Again, we knew that we would be building up quite a backlog at this period of time. From this point forward, we're going to be moving through those and working those numbers down.
What could your system run if there wasn't a midstream constraint?
Oh, 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 a dehy down or something like that. That's just the nature of the beast, and just a lot of moving parts in a large gathering infrastructure system like that. It'd be right speculation, but I'm sure we've hit over 1.5 Bcf. I think the record was at 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.
Thank you.
Our next question is from David Deckelbaum of KeyBanc Capital Markets. Please go ahead.
Hey, Dan. Hi, Scott. How are you guys?
Good.
Good.
Okay. How many frac stages do you have waiting? I'm looking, you're going to drill about 155-170 wells, and lots of those coming maybe in the second half of the year. If I run the numbers in a way, your 2015 guidance, granted, has some upside, but it looks quite conservative, maybe. Could you-
Yeah. Well, 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 1,400 stages, David, right now that we have in the queue. The good news is that we've been able to continue our production profile. We've been able to sequentially grow, though slightly, 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 realize in the first and second quarter.
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.
Yeah.
I feel very good about it. 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 a permit in West Virginia, in Wood County. What are 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.
I know. Okay.
We are extending a look at the play south of where the drilling has been, and we think our fairway is in the volatile window, and we think that we have an opportunity there. Yes, that is one of the sections that we're looking at.
Thank you.
Thank you, Jack.
Our next question is from David Beard of Bria. Please go ahead.
Hi. Good morning, gentlemen.
Good morning. How you doing, David?
Good. 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, firm sales, and the additional capacity that we expect to add to our inventory. As Jeff mentioned, to get to the 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.
All right, great. Thank you.
Thank you.
Our next question is from Matt Portillo of TPH. Please go ahead.
Good morning, guys.
Hey, Matt.
Just a quick question. I wanted to clarify, heard a lot of great detail on 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 of months ago, where you laid out your 2015 firm capacity at, I think, about 1.1 Bcf a day. Could you just give us some color of how much that's changed on a relative basis and where we sit at the moment?
Sure, Matt, this is Jeff. The numbers have improved somewhat from that presentation, but I wouldn't say they've improved a great deal. We have a lot of deals that we're working on that we're close to wrapping up. We have some opportunities that is out there that we're close to wrapping up. Probably the biggest number I add to the slide is our new capacity into the utility there in Northeast PA. That will be added to that chart at some point.
Great. 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 of your 2014 production in terms of exposure there. How does that look currently in 2015, just from a rough estimate perspective?
I hadn't broken that out. We can get back to you on that, on an exact percentage. We're going to be growing the production, so that number will probably increase slightly. I'll have to get back, I'm sure you'll see it, Matt, in one of our future presentations.
Great
Once we get more granular on our 2015 guidance.
Perfect. Just last question from me. I was hoping that you could talk a little bit about the organic leasing opportunity you see today within the Eagle Ford, and any appetite in regards to M&A in the basin. Thank you.
Okay, Matt. Organic leasing, it is what it is. We continue to talk to owners of the unleased acreage out there, we think there's an opportunity to pick up additional acreage. 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. If the opportunity rises, 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 our organic approach is more prudent for us at this stage.
Thank you very much.
Thank you.
Our next question is from Wayne Cooperman of Cobalt Capital. Please go ahead.
I'm sure that this has been asked in 100 ways. I'm just wondering, people are really worried about pricing. I wonder, at what price 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. I'm not going to state just a price that we're going to shut in. If the market looks like it's behaving in a way that it would be prudent for us to shut in gas today and sell it near term, then we look at that. 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.
Dan, let me just try to rephrase that a little bit differently, then. 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. Therefore, the differentials that you're seeing now should dissipate over time. 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. At this stage, again, our realization was $3.74 for this last quarter, and we were 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 invested dollars.
Right.
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 blowout, and somebody wanted us to move a gas for $1.
Right
We're not going to move it for $1. 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. I understand your question, and there's merit to it. Just right now.
Is there some limiting factor to how low a price can go in your market? Or there's really nothing to stop it from trading at $1 or $2 in a bad part of the market?
Well, I think if you look at all of the producers up 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 P.A., but there's other gas flowing into those pipes to saturate the market. I think there is a price out there that industry would say that we're just not going to move our gas for that. It's more valuable than that, and we're just not going to move it. There is that price point. What it is exactly, $1 or $1.50, I don't know where it might be $2. 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.
Yep. Thank you, Wayne.
Our next question is a follow-up from Joe Allman of JPMorgan. Please go ahead.
Yeah. Thanks again. Just, Dan, thinking about your ability to take on some extra capacity. If there's extra capacity in the system, why are the differentials around a negative $0.70? I'm just trying to get my head around that.
Well, I try to get my head around it also, and one of the things that we're looking at is when you, and 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 supposedly two parties, a buyer and a seller, are willing to move gas for. I question the differentials, and particularly the number of contracts that are steering a large volume of gas, and we're looking into the transparency of all of the transactions, though 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.
I'm looking at it to try to understand it a little bit more in detail also.
Yeah, Joe, I think the improvement we've seen in pricing has a couple of 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's excess capacity up there, but just how much more incremental demand is there certain parts of the year? I realize that we expected improvement in the differentials when we had a good winter, and they did improve. They didn't 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 the firm sells, and particularly our last deal with Cove Point and Washington Gas, to make sure that we actually have someone that burns the gas. Having an $850 million a day, 15, 20 year contract for people that do burn it was very important to us. Yeah, I agree with you. I don't understand exactly the dynamics that would cause a $0.70 differential at this point. It has been a big improvement over the last 60 days.
How much of the incremental capacity that you expect to take over the next several months, how much of that is actually new capacity? How much of it is you actually just taking someone else's capacity? For example, that 150 million a day from Millennium in September, that's new capacity?
No, that was existing capacity. Just hadn't been bought yet, and we bought it. 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 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 it's 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 higher prices. 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 want it to start. For all the producers in the Marcellus as a whole, there's a constant jockeying around of positions on capacities to make sure that gas flows every day and that backs are as high as they can be.
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 open season that Millennium's having?
It's the 200.
Okay, that capacity, when you say it's new, it's new to the marketplace. It's existing in the pipe. It's confusing terms. We're out there. We 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. 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 are using their resources to try to increase their throughput. They're constantly looking at ways to add capacity to the system. As contracts get taken, it could open up space for gas to move in different directions. It's just something that all the producers and shippers and markets face on a day-to-day basis.
Got you. Okay. Very helpful. Thank you.
This concludes our question and answer session. I'd like to turn the conference back over to Mr. Dinges for any closing remarks.
No, 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 points. Otherwise, we would've not put those early guidance points out. When you look at what we have to be able to deliver in the future, we're going to, I think, 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 confidence that we're going to be able to continue to enhance shareholder value on out into the future. It certainly should give the shareholders confidence that the asset package we have will be able to deliver that value.
Again, thanks for the questions, we will see you next quarter. Thank you, Emily.
Thank you. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.