Good morning. Welcome to the Cabot Oil & Gas Corporation third quarter 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 your 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.
Thank you, Emily. Good morning, all. Thank you for joining us for this call. I have a number of members of the executive team with me today to assist in the Q&A session. Before we start, let me say the standard boilerplate forward-looking statements included in the press release apply to my comments today. On the call today, we will plan to cover the following: our third quarter 2013 operating and financial results, an update on our operations in the Marcellus and Eagle Ford, and finally, an update on our guidance for 2013 and 2014, including our capital budget and operating plans for 2014. Before I go into the details of these topics, let me start with the financial highlights from the quarter, which was, by the way, one of the best quarters we have had.
For the third quarter, we produced 107 BCFE of total company net production, or approximately 1.16 BCFE per day, which is an increase of 61% over last year's comparable quarter and a 13% increase sequentially over the previous quarter. Liquids production increased 43% over last year's comparable quarter and 18% over last quarter, driven by a 28% sequential increase in our Eagle Ford liquids volumes. Net income grew significantly during the quarter, increasing 91% over last year's comparable quarter, while net income, excluding select items, increased 73% over the same period. In the third quarter, we also continued to generate robust cash flow growth, with discretionary cash flow and cash flow from operations increasing 69% and 61%, respectively, over the last year's comparable quarter. Excuse me.
Our third quarter unit cost of $2.97 per MCFE were down 15% over last year's comparable quarter and down 4% relative to last quarter, continuing to demonstrate how our already industry-leading cost structure continues to trend lower. In fact, our cash costs for the third quarter were only $1.25 per MCFE, down 19% compared to last year's comparable quarter and down 8% relative to last quarter. Our natural price realizations were approximately 96% of the average NYMEX last day settle price for the third quarter, which exceeded expectations based on the midpoint of the basis differential guidance range we provided in early September. Let's move to our Marcellus highlights. Our operations in the Marcellus continue to provide peer-leading well results across our acreage position.
In our press release yesterday, we highlighted the results from several of the recent wells that further reinforce the productivity and consistency of the wells in our operating area. These results included 13 wells from a total of four pads. As you can see, we are still drilling just a select number of wells from pads. We have not yet got to the full pad development drilling. These wells were completed with a total of 272 stages for a peak production rate of 323 million cubic foot per day. Very impressive results from our team in the Marcellus on the execution of our operation and an equally impressive demonstration of the quality of Cabot's Marcellus position. These results highlight the true differentiating factor of Cabot with the most economic wells in the Marcellus, and I think it is without question.
You can cut the publicly available data a few different ways and arrive at the same conclusion. When focusing on initial production rates, the previously mentioned wells, on average, had an IP rate of 5.4 million cubic foot per day per 1,000 lateral feet and a 1.2 million cubic foot per day per completed frack stage. This is not just a case of our wells coming online strong with open chokes and dropping off immediately. The average 30-day rate for these wells was approximately 90% of the IP rate.
While this is only a sample of our wells from the third quarter, these results imply an increase in an IP rate per foot and per stage compared to our typical 14 BCF well from our 2012 program, which is especially impressive considering our 14 BCF well was already best in class among Marcellus producers when comparing EUR per lateral foot of 3.4 BCF. This compares also very favorably to today's public data for Marcellus players. While we do not provide updated EURs and reserve data until year-end, I will say that on average, our 2013 program lateral lengths are several hundred feet longer than our 2012 program, and we are using approximately 200-foot spacing between frack stages on all our wells. As a result, we are completing three to four extra stages per well in our 2013 program as compared to our industry-leading 2012 program.
Also, I recently reviewed our forecasted drilling programs for 2014 and 2015, and I can tell you that a portion of the increase in our 2014 program, and that is an increase in our capital program, is a result of longer lateral lengths and more stages per well than our 2013 programs. Additionally, our 2015 program will provide yet longer laterals and more stages. Regarding pricing sensitivities, even in our highlighted low case pricing assumptions for 2014, we still generate greater than 100% return. While there has been a lot of focus on near-term pricing over the last few months, we believe, as this quarter highlights, the focus should be on the fact that we have the most economic resource in the U.S. What the third quarter also shows is our ability to exceed growth expectations while producing record results in a tough price environment.
Let me move to some comments in our Eagle Ford operation. Beginning in the third quarter, we redirected our focus in South Texas to our Eagle Ford program. It is beginning to pay off as we experience strong sequential growth with Eagle Ford liquids production increasing by approximately 28% over the second quarter. As we discussed on the second quarter call, we added a second rig in the Eagle Ford in August, which is solely focused on pad drilling. We will continue to operate 2 rigs in the play for the remainder of the year. We also noted in last night's press release the substantial cost savings we have realized with our most recent drilling and completion operations.
On the previous call, I was asked what it would take to accelerate the Eagle Ford operation above our 2-rig program. I said we were hoping to see returns of 60%-80%. Based on the results we are seeing from the longer lateral wells and the cost savings we're realizing on the drilling and completion activities, I think those returns are achievable in a consistent manner. As a result, we continue to be excited about the future of our Eagle Ford program. We will have more incremental results to discuss on the next call as a result of the multi-well pad drilling we are currently conducting. All right, now I'm going to move to our 2013 and 2014 guidance.
Based on our year-to-date production, we feel very comfortable reaffirming our full year 2013 production guidance of 44%-54%, even assuming a loss of the quarter of production associated with the sale of the Marmaton and West Texas properties. Also, despite our strategic decision to hold back certain volumes periodically due to pricing in the day market in the third quarter, our robust growth in the third quarter further reinforces our ability to grow not only production, but also cash flows in light of the headwinds related to natural gas pricing. We anticipate fourth quarter realized pricing will be stronger than we saw in the third quarter with an unhedged basis differential guidance range of +$0.10 to -$0.30 relative to NYMEX. However, regardless of pricing, we fully expect to meet our production guidance for the year.
In regards to asset sales, we made it clear that the Marmaton was a potential candidate for divestiture due to the focus elsewhere and the resultant lost opportunity in this area without sufficient capital deployed. The small legacy West Texas piece was not strategic and never received the desired capital. The implied metrics for the deal were very compelling compared to the recent transactions. The proceeds will make Cabot cash flow positive for the year. For 2014, we are reaffirming our 30%-50% production growth guidance. Capital spending for the year is expected to be $1.375 billion-$1.475 billion, based off a 7-rig program in the Marcellus and a 2-rig program in the Eagle Ford. Approximately 85% of our capital budget will be spent on drilling and completion activities.
75% of the drilling and completion capital will be allocated to the Marcellus, and the remaining 25% will be focused on the Eagle Ford. We plan to drill 170-190 net wells next year, with 130-140 net wells in the Marcellus and 40-50 net wells in the Eagle Ford. Virtually all of our wells are 100% working interest in both areas, and I suspect our 2014 net well count is considerably less than our peers and will still deliver best-in-class production growth. Our basis differential assumption for full year 2014 is a range of flat to NYMEX to-$0.40 per Mcf. Even at the low end of that range, again, we will generate a free cash flow positive program. Our unit cost guidance for 2014 is expected to decrease by 10% at the midpoint relative to 2013 unit cost guidance.
On production, we have been continuously asked about what factors are driving the low end and high end of our production range. I do not plan to get into the granular details around each assumption that was made. However, I will say that we ran multiple sensitivities internally, as we always do in our budget processes. Even assuming a reasonable level of curtailments throughout the year, our production growth remains well above the low end of our guidance. As we have done in previous years, we will review the guidance quarterly, and to the extent we feel we need to update the range based on current information, we will do so. Cabot has generated three consecutive years of annual production growth over 40%, and the midpoint of 2014 guidance implies a fourth consecutive year of 40% production growth.
More importantly, assuming the current strip and the continued reduction in our unit cost, we expect cash flow growth to outpace production. While these top-line growth numbers continue to be best in class, given that we are doing it with a cash flow positive program, our relative debt-adjusted growth numbers will be very compelling in an industry known for more outspending cash flow. As we have previously discussed, based on our budget, we expect to be free cash flow positive in 2014. However, the magnitude of the free cash wedge will ultimately be dependent upon the pricing dynamics in the Marcellus during the year.
Given the addition of a sixth rig in August this year and a seventh rig beginning in early 2014 for our Marcellus program, and the magnitude which we can increase our production with this level of activity in the Marcellus, we will consider further acceleration of our high margin, high return Eagle Ford program, assuming we do continue to deliver the results we expect. Changes to our distribution policy will be the primary candidates for the use of free cash in 2014. As it relates to distribution policy, in the past, we have ranked an increase in our regular dividend as a high priority, which was evidenced by the 100% increase in our regular dividend in August. However, in light of our recent underperformance in the market, share repurchases have become increasingly more attractive, as we believe there is a disconnect between our market valuation and our intrinsic value.
As a reminder, under our current share repurchase plan, we have authorization to repurchase up to approximately 10 million shares, which certainly can be increased if the situation warrants. Finally, a couple of comments around our marketing effort. With regard to pricing, we mentioned earlier our overarching assumption for the full year 2014 is that our average realized price will range from flat to -40% compared to the NYMEX last day sale price. This assumption includes the potential for seasonality outside this range. Additionally, the low range is representative of weak third-quarter index levels that we saw, and persisting continuously throughout 2014, which we do not expect. Our sales strategy remains unchanged as we combine our winter and summer sales with our long-term firm sales, while also utilizing our firm transportation position.
This approach will allow for approximately 5% of our volumes to reach the day market, which is generally necessary for operational purposes. Collectively, we have already placed over 1 Bcf for the 2013-2014 winter period and approximately 900 million cubic feet a day for the April-October summer period for 2014. These positions will certainly be expanded on in the normal course of business. Regarding our hedging strategy for the year, we currently have approximately 30% of our 2014 gas volumes hedged at the midpoint of our guidance range at a floor of $4.10 per Mcf. We will continue to lock in additional NYMEX hedge contracts throughout the year when the opportunity arises. Given the fact that a significant amount of our volumes are already contracted at a fixed premium or slight discount to NYMEX, these hedges will help reduce volatility in our overall realized prices.
In closing, we certainly remain enthusiastic about the future of both our Marcellus and Eagle Ford effort. Yes, we will have near-term headwinds, just like the entire industry will have in various different places at times. We will continue to adapt and adjust to respond to those circumstances. Even with all the negatives in the last eight weeks, this quarter for Cabot ranks as one of the best all time. As one of you has recently mentioned, in the end, it's the rock and the economics that matter, and we still have one of the best, if not the best, in that regard. Emily, with those brief comments, I'll be more than happy to answer any questions.
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're using a speakerphone, please pick up your handset before pressing the keys. 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 Drew Venker of Morgan Stanley. Please go ahead.
Well, guys, thanks. Dan, that was a lot of great detail you had.
Hi, Drew.
On the buyback program, are you currently authorized to start buying back shares? Can you offer some more color on where that program could go?
I'll answer that.
Drew, this is Scott Schroeder. We have had an outstanding buyback authorization for a long period of time. With the splits and the adjustments in it is up to just under 10 million shares. We're fully operational if we choose to go in and buy shares on weakness at various points in time. It'll be a more after the fact disclosure, where we just wanted to, in light of all the questions we had around free cash flow, in light of the weakness of the stock, we wanted to be more proactive in saying that we do have that as an arrow in our quiver, and we will use it when we see it appropriate.
Okay, thanks, Scott. It looks like if we look ahead, you could be generating more cash flow than I was thinking before, at least. Are you guys open to maybe looking at acquisitions or expanding into new areas, whether that's organic or acquisition based? Do you have any thoughts there?
Well, Drew, with our current capital guidance that we've given, we have several areas that have been included in that capital exposure that are exploratory in nature. If in fact those are areas that yield returns that are competitive with our existing projects, we will consider expanding into those areas. At this time, we have also continued to pick up some acreage in the areas that we operate. We do not have plans and are not focused on, excuse me, buying a bolt-on in an area that we are not currently exposed to.
Okay. Lastly, just on well costs, I guess given that you're talking about longer laterals, bigger wells overall going forward, where do you see well costs going from here?
Well, the well cost, again, when you look at the average and you look at the nets that we have in 100% working interest wells, the increase on the drilling side is typically not that substantial, because the drill rates and penetration rates are so robust. The incremental add that we have will be by virtue of more stages in those longer laterals. In our pumping services, we have very good contracts on our pumping services, and the uptick will be a direct proportion to the incremental number of stages. I would say probably anywhere from $250,000 to $500,000 on some of the expanded wells that we drill.
Okay. Dan, can you remind me where you are right now with well costs?
Well, we've still used, as we have highlighted in our discussion points in our presentation, our 14 BCF well, for example, in the Marcellus, that is around the six plus million dollar range. In the Eagle Ford, we have highlighted, particularly in our press release, with the most recent drilling that we've been able to do, we're on a pad right now. We haven't gotten to TD, we're drilling pad wells there with a walking rig. We think, again, reiterating what I've said in the release, that we think we're going to be saving, just on the drilling side, $500,000 to $600,000 per well in the Eagle Ford, and we think we're going to get our well cost below the $7 million range.
Okay, thanks.
Thank you.
Next question comes from Doug Leggate at Bank of America, Merrill Lynch. Please go ahead.
Thanks. Good morning, everybody.
Good morning.
Dan, again, thanks for all the detail on the call. The 100% working interest wells this year, is that more of a high grading exercise, or how sustainable is your drilling program at that level? Maybe you could help us with the average working interest across the two plays currently.
Yeah. It is a little bit of an aberration as we go into 2014, there is a couple of reasons for that. Excuse me, Doug. The couple of reasons that make the majority of impact is one, through 2013, we had a significant level of joint venture wells that we operated and we drilled in our joint venture with Osaka. From a net perspective, we had a number of gross wells in there, but we didn't net out the higher percentage because of Osaka's interest. Additionally, by virtue of the sale of the Marmaton up in Oklahoma, we had a number of non-operated wells up in the Marmaton that we participated in, and we also had on the operated wells, we also were anywhere from, say, 35%-85% working interest in the operated wells.
That was one of the reasons why we elected to refocus into our core areas, where we have blocked acreage and where we can have greater efficiencies at 100% operated wells. Going forward, we do anticipate that by virtue of, again, having two anomalous events, the JV and the Pearsall and the sale of the Marmaton, that we will have a much, much higher working interest % on average, than we have in the past.
Really helpful. Thank you. I guess my follow-up would be, your prepared remarks you talked about, you expect in your capital review, your plan for next year and the year after, you expect longer laterals, even sequentially, 2014 over 2013 and 2015 over 2014, also more stages per well, I guess. Can you just help us understand, how much further do you think you can go in terms of improving the efficiencies of these individual wells? I'll leave it at that.
Okay. It's a good question, Doug. Industry as a whole has certainly been pushing the limits of extended laterals and reduced spacing on frack stages. Some other ideas being tried is increased proppant per stage. I think industry will continue to tweak and try different ideas that would enhance the efficiencies. In our Eagle Ford operation, as an example, we had averaged 4 or 5 thousand foot type laterals in a pad that we are currently on right now. We are going to average out to 9,000 foot on those particular Eagle Ford locations on that pad. How much further you get out is, at least in our sense right now, beyond 9,000 feet is going to be pushing it, with current technology and current efficiencies, to be able to assure yourself you're getting effective fracks at the toe stages.
Nevertheless, as you can see, going, say, from 5,000 to 7,500 or 9,000 certainly is a step further out in the Eagle Ford. In the Marcellus, we continue to extend our average lateral lengths in those particular wells. We have some wells that we have planned for 2014 that would allow us to place 40 or so stages in a particular well. We are extending them out further. It's not going to be as aggressive of increase as you have seen in the past, by industry as a whole, I might add.
Great. Thanks, Dan. Look forward to seeing you in Miami. Thanks.
All right. Thanks, Doug.
The next question is from Charles Meade of Johnson Rice. Please go ahead.
Good morning, everyone. Thanks for taking my question. I was wondering, Dan, could you give us an idea on both the timeline of these long lateral Eagle Ford wells that you're drilling, the timeline we should expect results on, and really, what kind of rates you're looking for out of those wells?
Yeah, Charles, that's a good question. We have, again, on one of these pads we're on, we have drilled six of the top holes on a six-well pad, and now we're going back and we're starting the laterals on that six-well pad. As a placeholder, we had completed a four-well pad, and we completed that four-well pad that had a measured depth of 58,000 feet, and we completed it in 58 days. A pretty simple thousand-foot average throughout four wells on that particular pad. I don't know if that will hold true, Charles, as we get out even further with the lateral lengths, but that gives you a benchmark to work with.
Got it. The key thing here, though, is that you're batch drilling, and are you going to do a batch completion on that pad as well?
Yes, we will.
Got it.
Yes.
And then the-
Just one other quick point, Charles, on that. That's the reason I said, well, when we come out with the data. We will probably have something at our year-end call in February, we would hope, a little bit more color on results of these wells. The six-well pad is probably not going to be a great lot of time on that particular pad site, but we should have some more color, certainly, on our year-end call.
Got it. It'll be a lot of oil when it does come at you.
Yeah. We're hoping, yeah.
Right. The other thing I wanted to ask, just to touch briefly on this Northeast differential issue. I looked up at one of the regional hubs up there's actually been a dramatic, or there's been a pretty quick tightening or narrowing of the basis just in the last week. I was wondering if you could We're close to a third of the way through the quarter, and I wonder if you could offer a few more thoughts on how it's looking for the last two months of the year.
Well, I'll let Jeff just add some brief color to it, I will say this. I looked at it. We had our board meetings, of course, yesterday and the day before, and kind of glanced at it. I don't know, one of the indices was up $0.72. Again, volatility is the name of the game. We ran through a lot of sensitivities, as I mentioned in the little talk here. We think it's going to be volatile. There's going to be times when we don't like the number, there's going to be times that we can catch up. Through all that sensitivity, we feel like the range that we've given is supportive. Not only that, with the type of wells that we're drilling and the unit cost discounts that we're seeing, our return profile for this program is going to be significant.
In fact, if you back up a little ways, you take the noise out that's been most recently discussed in regard to the most recent past differentials, our returns are probably going to compete against returns that we had when we didn't have this differential noise.
Got it.
I think Jeff wants to make a comment also, Charles.
Yeah.
Thanks, Charles. I'll get a little more specific with your question. The Leidy Line that you're speaking of has seen great improvement just in the last week, although I will say it's been improving the last 6 weeks, little by little, as Tennessee has improved as well, demand has improved, some of the other pipes. I think on the Leidy Line, the volume of gas that reaches that pipeline is pretty much at its max. The pipe is full. What's been missing up there has been the demand. Now the demand piece has shown up. We're going to see improved pricing there. In fact, I think yesterday's gas day was maybe a nickel under NYMEX, a big improvement.
On Tennessee, with that pipeline opening up on November 1st with the new capacity and the Bcf a day, essentially going about 300 going west and about 700 going east, the transportation opportunities and the paths have opened up, and we've seen a big improvement there. Not quite like Transco's Leidy Line, but we expect to see, as winter progresses, more flattening of that basis as well.
That's great detail, Jeff. Thanks for your time.
Okay.
Thank you, Charles.
Our next question is from Pearce Hammond of Simmons & Company. Please go ahead.
Good morning, guys.
Hey, Pearce.
Were there any one-offs that impacted Q3 Marcellus differentials, like pipeline maintenance, things like that are worth highlighting, which may not be repeatable, say, next year?
Yeah, I'm going to flip that right off to Jeff, Pearce.
Okay. Yeah. Particularly in the third quarter, we had, I wouldn't call it as bad as a perfect storm scenario, but we had a number of scenarios that changed the dynamics of pricing, particularly on Tennessee. Obviously, they had construction all summer to facilitate the new capacity coming on November 1st. That was hammering some of the areas that normally you did not see reduction in capacity. We also had folks taking gas off Tennessee, trying to get to other locations that were already full. That also intensified the problem. The weather, I don't want to harp on how mild the weather was, but the lack of power gen on that particular pipeline, it is very sensitive to demand regarding weather, both winter and summer. We had that occurring at the same point.
There was obviously a little bit of new production that came on that also added to that scenario. Overall, we think that with this new capacity and normal weather conditions, that we'll return to a more historic type basis.
Thanks, Jeff. Dan, what are your thoughts about de-risking other horizons on your Marcellus acreage? I know you've done some completions in the past in the Pearsall, but what about something like the Onondaga?
Well, Pearce, one of the processes and procedures that we're going to be able to get to in our 2014 program is the examples of pad drilling that we've been discussing. Pad drilling means getting to the six, eight, 10 wells per pad, maybe 12, 14 wells per pad. The opportunity at that time will allow us to try multiple ideas on that particular pad that would allow us to look at analogous similar geology, and the information and data points we get from that similar geology will allow us to maybe make a little bit better interpretation of what the results are telling us. Some of the things that we're going to try to accomplish, which are going to be reduced spacing in the Lower Marcellus.
We'll have also the Pearsall tests, we'll have the Upper Marcellus tests, and we will look at any other ideas that we have in additional rock that might be something for the future. That's the time we're going to do that, Pearce.
Thank you, Dan.
Yeah. I would say towards the end of 2014, we would be able to give you some additional color on all those points.
Excellent. Thank you, Dan.
Thanks, Pearce.
Our next question is from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Hey, Brian.
When we look at your end markets for gas, I think you had said about 65% of this year's contracts are linked to Henry Hub. Can you talk to what that number is for next year? How does the relationship to Henry Hub of next year's contracts compare with this year's?
Okay. Yeah, I'll let Jeff give you a brief executive summary on that.
Yeah, Brian, the 65% for 2013, we're going to look at growing that number for 2014, just because of the production growth. What I'm trying to say is most of the next round of contracts pertaining to the production growth will be tied to NYMEX-based contracts. It's pretty much as simple as that. As far as what's going on in 2014 compared to 2013, as we've talked about before, we took great lengths to put together all of our portfolio of contracts and transactions to be able to supply you with this range for pricing going forward. If you try to compare that to pricing 2013, I know we were relatively flat to NYMEX in quarter one and quarter two, then you saw the results for quarter three, we're probably pretty close to our guidance for four. You can work the numbers from there.
Okay. Just to make sure I understood the early part of your response, when you talk about adding new volumes to increase the number, are you increasing the percent above 65%, or are you keeping the percent purported the same to be just adding contracts given your growth?
The % will grow.
Okay. Thanks. Then when we think about the key milestones to meeting the midpoint of 2014 guidance, can you just walk us through key items that you see on the critical path regionally within Susquehanna County? I guess one would assume if you get the rig count ramped up on schedule, those items on the critical path would be more from a midstream perspective.
Are you talking about our production volumes, Brian?
Yeah. For us to have confidence that you are at versus above versus below, or for you to have confidence that you are trending at versus above versus below your 2014 volume guidance, what do you see as items on the critical path as you go forward through 2014?
For one, on the operational side, I don't see anything that is going to deter us from achieving the volume rates that we have forecast. Operationally, one, we have a significant level of wells that we're going to roll into 2014, and a significant number of stages in those wells that we'll roll into 2014. With the level of drilling that we have between now and then, and the addition of the seventh rig, I think we are going to be able to meet or exceed the guidance that we've given with our operations program. The length of laterals, the number of stages, and our ability to secure the pumping fleets up there are all within our reach, I see no issues in regard to that.
The 30%-50% guidance we gave, as I've talked through in the teleconference write-up. We are looking at all the sensitivities on us pulling off, even throughout the full year, us pulling off production that would be representative of some of our day gas. Even in light of that, we have a significant opportunity to meet or exceed our production guidance. Any key milestones, it's really going to be conducting our operations as effectively and efficiently as we have in the last few years.
Basically, there's nothing on the critical path from a midstream perspective. That's all in place, it is executing on the upstream and watching the markets to make sure that the demand is there, or are there key midstream items to think about?
There's not anything in the midstream that is going to be a critical path item for us to be able to achieve our rates that we forecast. In fact, at the end of 2014, we will have, in the form of compression dehydration and our measurement capacity, 3.4 Bcf available to us.
Great. Thank you.
Thanks, Brian.
Our next question is from Bob Brackett of Bernstein. Please go ahead.
Good morning. A couple questions. One, you mentioned the quality of the rocks early on as a kind of a commanding advantage. Have you guys ever benchmarked, sort of Northeast P.A., what advantage the rocks have versus what your own proprietary completions have?
Say that again? I'm sorry, Bob.
Can you separate how good the rocks are from how good your completion strategies are up in the Marcellus?
Okay. I appreciate that. Well, the feedback we get from the north region personnel is it's all their completion techniques.
As would be expected.
To quantify that, we do things in our completion operations up there. We were first movers. We discovered the Northeast Pennsylvania Marcellus, and we have developed it with the first drilling up there in that particular area. We have a core group of extremely talented individuals that have paid attention to it and have done their tweaking and evaluation. I certainly think what we do has some bearing on it. I also think that the Marcellus that we drill in our particular area is uniquely thick compared to the rest of the Marcellus you see across the entire state and into West Virginia. The maturity of it is at a perfect maturity that allows it to have a very low amount of connate water.
Our fracking and friability of that allows it to be extensively fractured with the fracs that we put on it, and I think the recoveries that we get of in-place reserves as a result of that, and not having any water in the system and any concerns about permeability issues down the road, we are in the absolute best spot you can find as far as reservoir quality.
The follow-up, you talked about differentials being flat to minus $0.40 off of Henry Hub. What's your view for Henry Hub for next year?
We haven't looked at the Henry Hub except to say that on average, we are going to be between the, say, $3.80 and $4.00.
Okay. Well, thank you.
Our next question is from Jeffrey Campbell of Tuohy Brothers Investment.
Good morning.
Good morning.
Just wanted to ask one question each regarding Eagle Ford and Marcellus. I'll go with Marcellus first. It looks like your average production per stage is spot on with the wells you highlighted in the second quarter. In the second quarter, you gave us some locational color with regard to the wells being north and northeast in Zick. I was wondering if you could give us some kind of indications of what the locations of the four pads highlighted in the third quarter are.
They were scattered throughout our areas. We had a pad site to the northeast. Not just the east, but to the northeast. We had a pad site to the south and southwest, they were scattered throughout our area. By the way, they were in four different townships.
Okay, good. That's helpful.
With regard to the Eagle Ford, about the time you guys were at our conference in August, you had reported an 8,000-foot Eagle Ford well that had basically no decline over a three-month period. I was just wondering if there's any follow-on data with regard to that well, and if you've seen any kind of similar type of behavior in the wells that you've drilled subsequently.
Yeah, I'll let Matt Reid respond to that and give you maybe what we produced to date, and it's still performing well.
Right. That's our Pickens B 16 well. Had a lateral length of about 8,200 feet, 30 stages. That well's produced 125,000 barrels in about 200 days. It still continues to produce at an equivalent rate of about 600 barrels equivalent per day. So it's been fairly flat. Great producer, good EUR. The wells we're drilling off the current pad will be similar and linked to the Pickens well.
Good. Thanks very much.
Thanks, Jeffrey.
Our next question is from Biju Perincheril of Jefferies. Please go ahead.
Hi. Good morning.
Hi, Biju.
A couple of questions. The wells that you highlighted in the Marcellus today, looks like even compared to some of the reduced cluster spacing wells that you had talked about earlier, it looks like there's an improvement. Other than longer laterals, are there other things you're doing on the completion front that is still driving improvement in productivity?
We have got our spacing down. A small portion of our 12 program had the 200-foot stages spacing, and all of our 13 wells, and our wells going forward are going to have that spacing. When you look at what we do on the completion side, again, back to the comment I made on, I think to Jeffrey, or Bob, the guys up there have continuously tried different techniques and processes on our completions, and we have a good database right now, and we try different things all the time.
Okay. As far as Northeast demand is concerned, I think you guys have been looking a pretty close look at it in a longer range plan. Anything you can share in terms of new market opportunities for pipelines or incremental demand?
Yeah. I'll chuck that to Jeff, Biju.
Yeah, Biju, it's an ongoing process for us as we look at different options getting out of Susquehanna County. I think if you follow the open seasons by the pipelines, particularly the non-binding open seasons, you see a lot of projects that are on the drawing boards that get gas out of the Northeast P.A., particularly to the Carolinas, to the Mid-Atlantic area, and additional pipe going, obviously, with Constitution and into New York here in November. I think the other thing that's a little bit missing from the equation is all the new projects in Southwest P.A. that will move gas, most likely to Canada, and obviously back on REX and all the backhaul projects and pipe reversals that are going on there will also influence the Northeast production and probably obtaining more market share of the projects that I mentioned previously. It's ongoing.
We have a number of ideas. We hope to expand on that in the next few months.
In the next few months, is it likely that we could hear from a kind of Cabot-sponsored pipeline like the Constitution? Is that, or is it other industry projects that you're referring to?
Yeah. Probably bad choice of words, the next few months. These projects take a long time to develop. I think the pipelines are putting them together as we speak. We're trying to make decisions on which projects are best for us. If it's more than one, just what share of those projects that we participate in. It's ongoing. There's more than a dozen that would benefit us directly. We're in the evaluation stage at this point.
Okay. Got it. Thanks.
Our next question is from Gil Yang of Discern. Please go ahead.
Hi. Good morning, gentlemen.
Good morning.
Just a couple of questions, sort of following up on some of the other questions. The role that you were talking about for going into 2014, are you in any way, because of the curtailments that you had voluntarily placed on, are there more wells sort of waiting to be turned on than you would've expected, and does that lead you to go into 2014 a little hotter than you would've originally planned and sort of make it easier for you to grow?
Gil, it's a good question. In fact, I think today's rate is probably a rate that is higher than maybe we've seen. The result is that we do have volumes that are upcoming with some robust completions that we expect, that we have risk, if you will, on the production profile we've included in our forecast.
Okay. The risk-
Curtailment issues.
Right. Not versus productivity, just-
Right
risking the timing of when they would come in.
Right.
Gil Yang, this is Scott. Just based on the simple math, we do have six rigs running in the Marcellus now. Just by the nature of that activity, we're going to have a higher number of completions going into the next year than we had last year.
Sure. Right. Okay. Then with regard to completions, have you given much thought to, or have you been also tweaking lateral spacings, or do you think you're pretty much optimized in terms of the distance between laterals or any chevroning of the laterals within the formation?
Yeah. Are you talking about the frack stage spacing?
No. Well, obviously you've gone down to the 200-foot spacing within the frack for the frack stage length, but I'm just talking about the spacing between the laterals-
Oh, okay. Yeah
that you're drilling.
Yeah. All right. Yeah, Gil Yang, that is, like I mentioned before, once we do get on some pads, we will be looking at reduced spacing. We will, and in fact, we have drilled a couple of wells that have gone down to 800 foot, and we will continue to look at what we think is a very optimal spacing. That is the plan, to continue to reduce from the 1,000 feet we have right now to something less.
Do you want to say, can you say what happened to the 800-foot spacing?
It's still too early.
Okay. Thank you.
Our next question is from Jack Aydin of KeyBanc. Please go ahead.
Hey, guys.
Hey, Jack.
Is any of those four pads that you had in the quarter, any of them is Riley pad, or Riley pad was not included in those?
No, we don't have the pipeline yet hooked up out there, Jack. I know we're still waiting on that, and the anticipation is that we would be able to get it hooked up this quarter, and we still believe that to be the case. Again, these are pads that are outside of the area where the majority of our drilling has taken place, and as I mentioned, they're in four different townships.
Yeah. Second question: Do you have other opportunities to acquire additional acreage in Susquehanna? Is there anything available to add on bolt-on in your acreage in Susquehanna, or did you do any purchases in this quarter?
Well, some of the purchases that we've done has just been by virtue of some of the small tracts, picking up the lessors that have, or the mineral owners that have desired to wait until there is going to be a well drilled near them, and in the event they lease on them. We have picked up some acreage in that regard throughout the year along those lines. As far as a bolt-on piece of acreage that we could buy, we're not negotiating any at this time.
Some clarification, Dan. You mentioned you placed 1 Bcf in 2013 at a fixed and about 900 Bcf from April 2014 to the end of the year. Is that fixed firm or what kind, could you clarify it a little bit for me? What do you mean by that?
Yeah, Jack Aydin, I'll let Jeff on.
Okay, Jack. What we were telling the world here is that we have 1 Bcf a day of gas already placed for the winter period. That's November through March of this year and first quarter of 2014. When we say placed, we mean we have that gas under contracts, and similar type contracts that we always have with splits between different indexes, but primarily based on NYMEX. We have approximately 900,000 a day for the summer period. That's April through October. It's already under contract. Those are all firm sales, and for the most part, we've utilized the majority of our firm transportation with those sales. We think we're in pretty good shape with a large majority of our gas already under contract.
Thanks, congratulations, guys. Good quarter.
Thanks, Jack.
Our next question is from Gordon Douthat of Wells Fargo. Please go ahead.
Yeah, good morning, guys.
Gordon.
Question on the lateral lengths for this year. At 200-foot spacing, I think you mentioned in your prepared comments you've added about 3 to 4 frack stages this year. Does that get you at about 47,000-48,000 foot lateral?
Yeah, that's good math.
Okay.
That's 47,000 feet.
I'm sorry. 4,700 feet.
There you go.
Yeah.
Scott will always get the numbers right. He's good with numbers.
I believe you had some of those on since 2012. I'm just trying to get a sense of what type of production history you need on those longer laterals with the tighter frack spacing in order to feel comfortable increasing those EURs.
Well, on the flowbacks and what we see early stage time on the wells that we have brought on, we feel very comfortable that we're going to have increases in those wells based on what we've seen through our other wells. The fit on the production curve is going to tell us fairly quickly that we can expect a better EUR. There's nothing that we see right now that's going to deter us from our position that EURs will be higher in 2013 than they were in 2012.
Okay. You mentioned that probably with the reserve report, the 2013 reserve report, you'd discuss that further. Is that something that you'd talk about in February?
Yes.
Okay. To what extent is that incorporated in 2013 production guidance also 2014 production guidance?
We look at what the production curve fit is for our normal wells out there, we use that curve fit, and roll it all the way through the year to come up with our production profile. From that sense, the EUR is applicable and used in what we forecast. I'm not sure I'm answering your question though, Gordon.
I'm just trying to get a sense of is there upside to the numbers? I know you've given some fairly wide ranges next year, what extent do you feel like I know production has been pretty strong, to what extent there might be more upside?
I think the guidance we've given is robust. I think the guidance we've given is going to be in the top of the class. We've made a statement in the past, Gordon, that if we wanted to grow by putting in, say, we put another spot crew in for four months, and we average a number of stages that we complete in a day is, say, 6. I can assure you that if that's what we wanted to do, that we could really increase our production profile. I'm comfortable with the range that we're in, I think you've seen in our past guidance that we have been probably a company that has underpromised and over-delivered, we're not going to change our methodology.
Okay. Appreciate the color, Dan. Thanks.
Thanks.
Our next question is from Robert Christensen of Canaccord Genuity. Please go ahead.
Yes. Thank you. Congratulations on managing this basis. I think doing a great job on it.
Hi, Robert.
Can you just please. Some of my question was previously answered. As an ex-pipeliner looking at all the projects that pipelines are putting up, how are the negotiations going with these pipelines, in terms of getting a deal done? Are you pleased, and could such a thing happen, where you'd have a big ride out or two out of the area, by 2015, get some steel on the ground in 2014 if you get behind one or two of these things, and then basically permanently end these worries over basis differentials? Give us a sense on how it's going.
Yeah. Well, I'll start, and I'll pass it to Jeff. Robert, when you look at the space and you look at the differentials, there's going to be a number of things that between now and 2017, and I know that's not the term you've talked about, but between now and 2017, now and 2016, now and 2015, that will make a difference in the takeaway capacity, in particular up in our area of the Northeast. If you look at some of the things that are going on away from us, and you look at maybe the intangible benefits, those are going to have an impact on us also. There was a question earlier in the Q&A session talked about. Are there anomalous events that have created a burden on differentials in this period?
Well, if you go back and you look at the southwest part of the state, there was a period of time that there was a purchase of a lot of the REX gas to be able to move gas and commingle with the volumes in the market that exacerbated, if you will, the problem. Some of that was a result of some Dominion issues that they had and maintenance things that they had down there. That had a direct impact during the third quarter that we don't think is going to be another recurring event. We think that there is a move afoot to reverse REX and take southwest gas in the west direction. We think there's projects that are going to be going down and alleviating some gas that is currently flowing east to flow in other directions from other areas.
We think Gulf Coast gas is going to be finding different homes versus flowing on the long-haul pipes up into the east. As far as pipeline negotiations, I'll turn it over to Jeff, and he can maybe make more detailed sense out of what I just said.
I'm not trying to invade the propriety of a discussion you may have. I'm just trying to get a sense of how well the discussions are going to maybe take gas to Atlanta for all intents and purposes.
Yep.
It's certainly dynamic times. It's actually kind of fun at this point to be involved in so many projects and also be in the position to offer up a substantial quantity of gas dedicated to some of these projects. We are involved in practically every single one of them in some way, shape, or form. We think smaller positions in some make more sense to us, but we also think the region, in general, needs a larger straw out of it, and there's obviously several very large diameter pipes planned to leave the area. You mentioned Atlanta. Obviously, there's discussions around that particular city as there is in Birmingham, Alabama, all the way from Susquehanna County to Birmingham on the Atlantic Sunrise project that we're very interested in.
As far as the negotiations themselves, obviously you want to be involved in a project that you think will work, and it has constructability aspects to it. Also, we want to make sure that the pipelines that we participate in are kind of slam dunk in terms of FERC approvals, those sorts of things. We work very hard to that end to make sure those things happen. I don't think you'll see any of the projects that are on the drawing board right now or have progressed to the pre-filing stage of FERC be built in 2014. I do think in 2014, with the projects that are coming on in November of this year, that we'll have spare capacity through that period of time. That's why we're pretty confident that we're not going to see some of the issues that plagued us in the third quarter.
With the current spare capacity coming on, combined with the 2015 projects that we know about, and I'll put Constitution Pipeline out there just for a moment, and try to give you a timeline for how these projects get built. We came up with the concept of Constitution Pipeline in November 2011. It's been two years. The good news there is it's just 17 months away, and in the pipeline world, that's not far.
Right.
It's going to put up a whole new world for us and others. These projects are on the three-and-a-half year horizon on completions. Keeping in mind the [BCF] that's coming on November was started about three years ago, and here we are.
They're ongoing, and again, I think we're in a very good position to be able to be a shipper on a number of projects.
Well, thank you very much. Great answer. Appreciate it.
Thanks, Robert.
Our next question is from Zach Berger of Conatus Capital. Please go ahead.
Morning, guys. My questions have been answered. Thank you.
Thanks, Zach.
Okay, the next question is from Matt Portillo of TPH. Please go ahead.
Good morning, guys. Just a quick question for me. In terms of the Marcellus, you mentioned longer lateral lengths over the next few years. I was wondering if you could give us some context in relation to your acreage position and how you think about the longer term, in terms of the lateral length you're able to achieve. Is that closer to 5,000-6,000 foot in lateral length? Or just how should we think about your drilling plans on a go-forward basis?
Yeah. We will be able to achieve over 5,000-foot laterals.
Perfect. Just in regards to your drilling plans next year, you mentioned a very robust 180-190 wells. I was wondering how your inventory levels will fluctuate around that and if you guys plan to maintain a similar inventory, potentially blow down some of the inventory you have or maybe see a little bit of build. Just trying to get some context around that.
Both areas will have significant inventories out in front of us. At 400-foot spacing in the Eagle Ford, we have over 500 locations, and we have over 3,000 locations in the Marcellus. We're stacked in multi-year inventory based on the number of wells that we project to drill in 2014.
I'm sorry. I apologize. To clarify that, just in regards to the drilling program, you mentioned 180-190 wells. How should that compare to the completion side of it? Are you planning to have a one-to-one drill to completion?
No.
Would we expect the inventory to build a little bit next year in the Marcellus?
No, we're going to have seven rigs running. When you drill several wells from a pad, and you have more rigs, say seven versus six, we would expect that just by nature, you're going to have some drilling activity happening on now seven pads versus six. That's going to have wells that will be In your term, backlogged and in the queue waiting to be completed. Yeah, we think that'll build a little bit. We also think that, obviously, the number of completed wells and completed stages will be increased also.
Great. Last question from me on the Eagle Ford. I was just hoping to get an update on how you're thinking about spacing at this point, in terms of the spacing between the well bores and potentially tighter spacing on a go-forward basis.
Well, there's a lot of different pilot programs being conducted in the Eagle Ford, different areas. Of course, each area is unique with its own unique geology. We have 400-foot spacing, and results from 400-foot spacing that we're comfortable with. We will try wells slightly closer and see if there's merit to that. Certainly at this stage, we're very comfortable with the data we have at 400 feet.
Thank you very much.
Thanks.
This concludes our question and answer session. I'd like to turn the conference back over to Mr. Dinges for any closing remarks.
Okay. Thank you, Emily. Appreciate the questions. I hope that we were able to clarify how we arrived at our projections and our guidance and the supporting data that we used to determine that. Again, I think the focus has been, for the last six or eight weeks, intently on the differentials. I think if you combined what our program offers and the continuing efficiencies that we deliver in our program, not only with the longer laterals and reduced costs, but our unit costs are going to continue to go down. I think the bottom line and the measure of what you might be able to accomplish and yield return for the shareholders, I think should be measured on what you can deliver in your report card at the end of the year.
With what we've seen in 2013 so far and what we see coming in the fourth quarter of 2013, I think we will be able to deliver a report card at the end of the year that will be very robust and indicate what type of capital efficiency our program yields. Additionally, with what we see in 2014 and the enhancements and improvements we see to our program in 2014, I am very confident that we'll be able to deliver an equally impressive report card at the end of 2014. Thanks for your attention. Goodbye.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.