Cabot Oil & Gas' (COG) CEO Dan Dinges on Q2 2014 Results - Earnings Call Transcript

Jul.24.14 | About: Cabot Oil (COG)

Cabot Oil & Gas (NYSE:COG)

Q2 2014 Earnings Call

July 24, 2014 9:30 am ET

Executives

Dan O. Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee

Jeffrey W. Hutton - Senior Vice President of Marketing

Steven W. Lindeman - Vice President of Engineering & Technology

Scott C. Schroeder - Chief Financial Officer, Vice President and Treasurer

Analysts

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Andrew Venker - Morgan Stanley, Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Subash Chandra - Jefferies LLC, Research Division

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Operator

Good morning, and welcome to the Cabot Oil & Gas Second Quarter 2014 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded.

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

Dan O. Dinges

Thank you, Youssef, and good morning to all. I appreciate you joining us for this second quarter call. With me today, as usual, I do have several members of the Cabot executive team. And also, before we get started, the standard boilerplate, the forward-looking statements included in the releases do apply to my comments today.

First, I'd like to touch upon a few of the financial and operating highlights from the second quarter that were outlined in this morning's release, I think, all of which indicates some positive numbers. Equivalent net production for the second quarter was 1.402 million -- excuse me, 1,402 million cubic foot per day, an increase of 34% over the prior year's comparable quarter. This also represents a 5% sequential increase over the first quarter, driven by a 4% increase in daily natural gas volumes, and a 39% increase in daily liquid volumes. Of particular note, oil production for the quarter increased 65% compared to the prior year's comparable quarter, when adjusting for last year's mid-continent and West Texas asset sales. Year-to-date, our equivalent production is up 34% compared to last year, in line with our current guidance. Discretionary cash flow for the quarter was approximately $332 million, an increase of 12% compared to the second quarter of '13. And then for the quarter, Cabot generated approximately $50 million of free cash flow, highlighting the capital efficiency of our program, and that's despite the lower natural gas prices. Net income, excluding selected items for the second quarter, was $115 million, an increase of 21% compared to the second quarter of 2013. Our unit cost, another area of improvement, continues to trend down, decreasing 16% year-over-year to $2.59 per Mcfe, with per unit cash cost of only $1.27 per Mcfe.

Let's move to the region. First, the Marcellus. The company continues to experience exceptional well productivity, as evidenced by the step-out results that were reported in today's press release. The consistency of our acreage to the north and east, while we expected these results, was confirmed by the step-out wells. It is still early in the production cycle, some of these wells, but we are pleased with the results today and expect the EURs per foot on these wells to be in line with our well results we reported at year end.

Net production for the field was 1.26 Bcf per day, up 4% over the first quarter, but did fall a little bit short of our internal expectations. This shortfall was exclusively a result of the ongoing issues directly related to gathering operations and not related to well performance. As we pointed out in the first quarter, Williams had experienced significant downtime with their operations during the extreme winter conditions. Unfortunately, some difficulties persisted throughout the second quarter, which were unrelated to weather. We have been in constant contact with Williams, and have recently seen operational improvements. However, throughout our discussions with Williams, we have made it very clear exactly what our expectations are moving forward, and we do believe Williams' operating results will continue to improve. Despite this unexpected dynamic, Cabot still achieved the midpoint of its production growth guidance for the first 6 months of '14, and we reaffirm our production guidance for the remaining 6 months of '14 and the full year of 2015.

During the third quarter, approximately 60,000 horsepower of additional compression will be added to our gathering system. This new capacity will alleviate high line pressure in certain areas and will also provide for compressor redundancies throughout the system. Having this spare capacity will definitely mitigate a significant amount of the compressor downtime experienced during the first half of the year. We continue to operate 6 rigs in the Marcellus, and expect to hold that rig count flat through 2015, based on our current operating plan. We plan to drill and complete approximately 60 additional wells during the second half of 2014. It certainly is nice to be able to operate only 6 rigs in a field and deliver top-tier production growth of such a large production profile.

Now let's move to the Eagle Ford, where we had some highlights. Our Eagle Ford team continues to work to maximize drilling and completion efficiencies in our core Buckhorn position in the oil window of the Eagle Ford. As a reminder, we currently have over 53,000 net acres in the Eagle Ford, with approximately 43,000 net acres at our Buckhorn prospect, which is located predominantly in Frio and Atascosa Counties. Cabot has 3 rigs drilling in the field, and by the end of the third quarter, all 3 rigs will be converted to walking rigs capable of effective, efficient pad drilling.

Pad development equates to drilling and completion cost savings in excess of $500,000 per well, and the facility cost attached to pad development is a cost savings in excess of $200,000 per well on a multi-pad site. The team has shown significant performance improvements in 2014, which has been driven by the continued optimization of our drilling and completion operations in the play, some of the recent initiatives, including drilling longer laterals, reducing the spacing between frac stages and increasing the amount of proppant per foot.

For the first half of 2014, our typical well was more than 25% longer than our average well drilled in '13. We have further reduced our stage spacing in the Eagle Ford, and modified the proppant size we use in our frac jobs, both of which have resulted in a significant increase in fracture conductivity. In the second quarter, our average stage spacing decreased 15%, compared to the average spacing for our '13 program. This equates to more stages per well and more proppant per lateral foot. In '14, we have also increased our proppant per foot by 15% to 20%, over our 2013 levels.

On the efficiency front, also, we continue to see an improvement in drilling days and drilling cost per foot. In fact, recently, we achieved a new record for us, for drilling days, drilling to TD in only 7 days for a 6,400-foot lateral well. As we highlighted in the press release, during the quarter, we placed 10 wells on production, that have now produced for at least 30 days. These wells achieved an average 30-day production rate of 840 Boe per day per well, with a 92% oil cut, from an average lateral length of 6,700 feet. The approximate well cost of these wells is about $7 million. Certainly, these wells are trending above our $500,000 barrels per BO -- per well EUR.

We also recently drilled and completed our first 300-foot down-spaced well, and have been pleased with the results to date. We will continue to monitor the production profile from this pad and have additional 300-foot space wells planned for the rest of our 2014 program. 300-foot downspacing could increase our location count at Buckhorn by 25% to 30%.

While we did not add a material amount of new Eagle Ford acreage during the quarter, we do continue to assess different opportunities throughout the trend, and anticipate adding more meaningful to our position throughout the balance of the year.

And now the remainder of my comments will be addressed to answer the possible questions we might have. In regard to pricing, we were certainly all aware of the pricing dynamics surrounding the Marcellus, and it continues to put pressure on the differentials throughout the Northeast United States, and the overall weakness realized -- in realized gas prices affecting all of the Marcellus and Utica producers. Cabot certainly is in this same position. As we continue to experience differentials that can be attributed to continued growth of supply, increased demand in the in-service of new long haul pipes designated to take Marcellus gas out of the region will certainly help the differentials. As we explained on our last call, we had certain winter contracts roll-off prior to April 1, and we anticipated slightly weaker realized prices for the summer period. As expected, for the second quarter, our realized prices before the impact of hedges averaged $0.89 below NYMEX, which is in line with the guidance we provided in our investor presentation. We expect our realized price point to be reduced slightly in the third quarter, and expect to see improvement as we enter the traditional heating season.

Moving to Constitution Pipeline update. We continue to make additional progress as we await the issuance of the final Environmental Impact Statement. The project is moving ahead on all fronts, as Constitution continues to acquire additional survey permits, right-of-ways and permits required to begin construction schedule for early 2015. We continue to see frequent updates from the Constitution team at Williams. And despite the delay we saw in FERC's issuance of the final EIS, there has been no change to the expected in-service date that Williams provided us back in December of '13. As a result, we remain optimistic for an in-service date of late 2015 to early 2016, but we do recognize several approval milestones do need to be met.

In regard to share repurchases, anticipating that question, share repurchases are still part of our capital allocation discussion internally. Year-to-date, we have not repurchased any shares. Currently, management is focused on balancing long-term development opportunities with share repurchases. Our near-term share repurchase activity will be coordinated with the success of additional acreage acquisitions and the corresponding acceleration opportunities on any of that new acreage we will acquire, and certainly, the share price is of consideration also.

In summary, even in this challenged pricing environment, we continue to generate growth in earnings and cash flow, led by our top-tier production growth. Current natural gas price realizations, certainly while not robust, are still manageable, and allow us to generate best-in-class returns. And add to this, the fact that our efforts in the Eagle Ford will continue to deliver strong oil growth, with our efficiency improvements and results. Plus, in an expanded rig count in the second half of the year, you will see these strong oil production growth. So what can you expect from Cabot is that we will continue to deliver strong production growth. We'll maintain a very efficient capital program, with excellent returns despite the differential effects. We'll add significantly to our reserve book. We'll capture margins with our continuing efficiency gains and operations and unit costs, and we will continue our efforts to expand our investment focus.

Youssef, with that, myself or the management team will be happy to answer any questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Dan, I want to say, I think with your last comments there, I think a lot of us, me included, scratched off a lot of the questions that we had planned. So I think you maybe -- there's been a theme on recent calls. So it's -- thanks for addressing that. I want to, if I could, get you to decompose a bit the results on those 3 pads, with the 191 stages. I know you said that they're in line with the estimates. And I guess, that means your EUR for year end. But can you discuss at all maybe some of the variability that -- when you're with North, and it got thinner, or when you went East, if there's any variance around that 1.25 Mmcf per stage?

Dan O. Dinges

Well, there's not a lot of variance, and each well can be unique in its own way, Charles. When you -- and that statement is consistent with the other areas we've drilled also. We have to make sure that we stay within the exact zone that we select. Down south, where it's a little bit thicker, we have a little bit more leeway to stay within that zone. But certainly, the thickness does not diminish significantly to the north, just slightly, and where we stay very vigilant on making sure that we stay within the zone that we're trying to target. But aside from that, we've been very pleased with the results. The frac spacing that we continue to play with, between 150- and 200-foot space fracs, we're toying with, and continuing to gather data in that regard. The flow back process that we employ up to the north and east has been similar. The type of frac we put on the wells was similar with the amount of proppant per stage and the pump pressures that we utilize. And the type of proppant has been consistent. So we are not seeing, again, any differences in either way, either it's our implementation and how we drilled a well, except being more vigilant and staying in zone, but our completion techniques in operation side is consistent. Flowback is the same, and as indicated, the results are good.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Well, that's great. I imagine you have to be quite pleased with that consistency. And if I could just take one follow-up, on the Eagle Ford, if I remember correctly, I think that on your last call, Dan, you were talking about that your organic kind of lease acquisition efforts were underway. And that, I think, you indicated that was your focus. Is that still -- is that correct? And if so, is that still your posture? Or are you may be looking more at maybe some producing property packages, as some people exit the play?

Dan O. Dinges

Yes. Well, we have evaluated through our internal team, not only the primary term or open acreage out there, but certainly, on small bolt-on type of opportunities, we evaluate also. Those bolt-on opportunities could come in the form of either just acreage or it could come with a little bit of production, but we're evaluating both.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. So you're agnostic on that. It's just -- you're just looking for value and how it fits with your existing position?

Dan O. Dinges

Exactly.

Operator

Our next question comes from Joe Allman with JP Morgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Could you talk about the differential, the gas differential, so far in July? And then, Dan, what are your expectations for the differential, cash differential in 2015?

Dan O. Dinges

Well, I'll let Jeff field that. But I will say this, just from an overall standpoint, that the differential by itself is going to be a certainly a moving target. But the differential will also be -- the final differential would be -- or the final realization would be affected also by the price of NYMEX. So as you see, the fluctuations in NYMEX, I think, you'll see the fluctuations also in what the exact differential will be. But I'll let Jeff answer the question in regard to the July and '15.

Jeffrey W. Hutton

Okay, Joe. I'm glad that -- excuse me, I'm glad that Dan led in with that quick summary on the differences that we expect to see between the differentials on our higher NYMEX number rather than our lower NYMEX number. July did come in slightly less than our average for the second quarter. That said, we've sort of expected that. We also expect that to continue as we reach the winter season. Again, weather will play a role here, and if we see a normal winter to a good winter, like we saw last year, we expect the differentials to strengthen a little bit. As far as 2015 goes, personally I don't see much difference between that year and this year in terms of differentials, but again a lot of that has to do with this winter and the weather we will experience then.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, no, that's helpful. And then a question on Constitution, so what are the key hurdles that can affect, whether that really comes on in late '15, early '16 or if it's delayed?

Jeffrey W. Hutton

Okay, Joe. This is Jeff again. Yes, the primary key hurdle is the final EIS statement. We expect that out in the next 2, 4 weeks or so. The certificate will follow under a normal process. With that, along the same path, we'll be -- and have been working with the New York DEC and the PA DEP on getting the permits necessary for our construction. But the final EIS is a significant event and our expectations are we'll see that on schedule. And the in-service date at this point, like Dan mentioned, in his speech, is still scheduled late '15 or early '16.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then lastly, just with Eagle Ford. I mean, Dan, it sounds as if you're planning on adding a significant amount of acreage in the Eagle Ford, and you previously talked about just some bolt-ons or potentially some production added with that. But are you also considering a bigger asset acquisition or might even consider a corporate acquisition?

Dan O. Dinges

Well, right now, we're looking at the asset acquisition being in the form of whether it's just additional leases or small bolt-on type of opportunities. The reason is very clear. If you look at our results that we've been able to post, with the type of wells that we're drilling, the efficiency gains that we've had that I've mentioned on the drill side and completion side. We have had in our investor presentation on a typical 500,000 EUR-type well will cost $7 million, and our lateral length being in this type well being consistent with the lateral length in the number of stages that we've done on our last 10 wells. At $90, we did over 60% return on that type of well. Two things in regard to these 10 wells. The 10 wells are trending above this type curve, for the Eagle Ford economics that we have presented. And certainly, our realized price is higher than the $90 that we've represented to get over that 60% return. So we are looking at the additional opportunities out there, with a economic improvements that we've seen and the efficiency improvements that we've seen to take advantage of any additional acreage we can fund.

Operator

Our next question comes from Drew Venker with Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

I'm wondering if you'd address the takeaway situation. Obviously, there's a huge amount of demand for additional long-haul pipe out of Appalachia in general. I'm just curious for your position, specifically. Have you examined building your own midstream solutions out in Northeast PA? And I'm thinking really, in addition to Constitution?

Dan O. Dinges

Yes, we have -- certainly, Constitution, we've talked about. Everybody's aware of it, that the commissioning of that particular pipeline will give Cabot an additional 500 million cubic foot net a day of gas, going through to a different price point. We have also -- are participating in the Central Penn pipeline, which is scheduled for the latter part of '17. Our participation in that is a -- if you will, a midstream investment. But more importantly, we're the foundation shipper on that particular Central Penn pipeline, and that will allow us to move an incremental 850 million cubic foot a day. And again, an anticipated commissioning of that in the latter part of '17. And I might add that, certainly, we're very in tune. Jeff stays up-to-date on every moving part out there in the midstream market, and we have ongoing discussions with how we're going to continue to move our gas, with the growth expectations that we have.

Andrew Venker - Morgan Stanley, Research Division

Partly, the question arose because the asset, really, is so tremendous that if you had adequate pipeline capacity, I think, you could grow at basically whatever rate you want it to grow. So maybe there are other considerations. Maybe the macro picture is a part of it. Are there other things you're taking into account when you evaluate your midstream needs?

Dan O. Dinges

Yes, we -- kind of back to my comment I made about drilling in a field with 6 rigs. Having a -- I don't know who's producing the most gas in the entire Marcellus or Utica area, but we're close to the either 1, 2 or 3, and at producing a 1.5 billion cubic foot per day up there and being able to grow off that base with only 6 rigs. I don't know who's producing the most, but I know that we have the least rigs running in the area, particularly with that growth profile off of that larger base. So we know we can continue to grow this tremendous asset, a 30 to 40 Tcf resource opportunity up there. We know the present value is important to all of us. So everything we do is to enhance the present value of that asset. A couple of things that will be happening in the future, we're all aware of. I think we all believe that demand is going to be enhanced. Whether that demand is in power generation, industrial use, LNG exports, all of that is moving forward. So we're optimistic. Though we are in a little bit of a lull period, we're optimistic that in the foreseeable future, demand is going to be enhanced. And I think that demand enhancement's certainly going to be coupled with the midstream efforts that are ongoing right now to attach the supply area to existing demand areas and incremental new demand areas. So we think we have a bright future.

Andrew Venker - Morgan Stanley, Research Division

Okay. And then lastly, can you speak to the potential you have in the dry gas Utica in West Virginia or even if there's some potential issue there?

Dan O. Dinges

Well, yes, we're in the Utica play. We have some acreage to the North, over 50,000 acres to the north area of the play, and we have some extensive acreage to the south area of the play, where we are. Whether it's the dry area or the liquids rich area, the Utica, we are looking at it. We're evaluating. We have a rig active at this point in time, still an exploratory project for us, but we're optimistic with the geology we see.

Andrew Venker - Morgan Stanley, Research Division

And Dan, is there a potentially get an update on well results this year?

Dan O. Dinges

Possibly. We're -- we can't guarantee anything at this stage, but it's certainly very possible that we could have some initial results this year.

Operator

Next, we have Pearce Hammond with Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

Dan, I was curious what your thoughts or plan was for '15 hedging?

Dan O. Dinges

Yes. We have looked at '15 hedging, Pearce, and we have considered it and looking at not only the -- NYMEX, certainly, it's just one component of it. But we had -- before, we've kind of changed our accounting process and now go to mark-to-market. We had tried to tie some of our -- and looked at trying to tie some of our '15 volumes to a particular pipe. But what we saw was: one, the -- it was not a fairly liquid market; and two, the differentials that we would have had to lock in, in advance, were punitive. And what we have seen each month is that the forward-looking curve gives a significantly higher discount than the actual month realizations, and we were not prepared to lock in those punitive differentials in advance in a illiquid market. But we -- as we've indicated -- or as we illustrated with our hedge book, we are interested in hedging, and we'll continue to try to find ways to mitigate the volatility.

Pearce W. Hammond - Simmons & Company International, Research Division

But it is your expectation that'll you put on some NYMEX Henry Hub hedges for next year?

Dan O. Dinges

Yes.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay. And then my second question is really strong oil production growth this quarter, congrats on that. Would you be willing to put out some oil production growth guidance for '14?

Dan O. Dinges

Scott's shaking his head, no. But right now, with us moving a new rig into the area, us looking at additional acreage out there and how we might move our activity around a little bit, I'm more comfortable just to be putting it out there with what we have. But I am optimistic that what we have out there is certainly reachable.

Pearce W. Hammond - Simmons & Company International, Research Division

And then one last one for me, and I apologize if you've already mentioned this in your prepared remarks, but what is current net production in the Marcellus? Or what does the month-to-date production look like there?

Dan O. Dinges

Gross production out there is -- we're working through these William issues that I've discussed, but we're over -- we're somewhere in between 1.4 to 1.5.

Operator

Next, we have Matt Portillo with TPH.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just 2 quick questions for me. I was wondering if we can get an update on how your downspacing test is performing in the Marcellus?

Dan O. Dinges

Okay. Just real quickly, we have several examples out there. We had a 10-well pad that we've been producing now about 9 months, about 9 months. We had our closest spacing on that pad. That spacing had the lower Marcellus spaced at 500 feet, and we still like the trend line on our curve from those wells. We do continue to look at and implement additional downspace opportunities. So -- but I guess, to say it differently, we are going to downspace further. So everything we've seen is positive so far.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And so is the plan there to potentially maximize the amount of wells you're able to fit in that section, potentially with a little bit of interference. So you're not seeing interference at this point?

Dan O. Dinges

Well, it's still early in the curve to be able to make that definitive statement. The answer is no, we haven't. But it's still early in the production cycle when you think about how you're going to be able to ascertain what is incremental reserves and what is acceleration reserves.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And just my second question, on the Eagle Ford, as you mentioned, you're starting to see the returns exceed that threshold you guys have talked about in the past. I'm wondering if you could provide a little bit of color around the acceleration potential? And then, I guess, just as a quick follow-up, in regards to the completions you're using in the basin, could you give us a little bit of color on kind of what your current completions are in terms of the size of the fracs you're doing and the number of stages you're completing?

Dan O. Dinges

Okay. On the acceleration side of the Eagle Ford, we have brought in another rig. We plan on implementing a walking package on a couple of rigs that do not have that capability today, which will help accelerate our efficiencies, as we've discussed. We've mentioned that we're looking and continue to look at additional acreage out there. With that opportunity, if we have success, I think you can anticipate additional acceleration, maybe another rig in that as a result of additional acreage. So that is also a way of doing it. When you look at the completions and you look at the 10-well that we recently did, the average lateral length was 6,700 foot or so. We had, oh, an average of 26, 27 stages in those wells. And the items that I mentioned, we're toying with the proppant size. We are looking at the amount of proppant per stage. So all of those things, we're gathering additional information on and we continue to improve with the -- again, are type of things that we're exploring out there.

Operator

The next question comes from Subash Chandra with Jefferies.

Subash Chandra - Jefferies LLC, Research Division

Following up on the Eagle Ford questions, 2 for me. One is can you be more specific just on the proppant intensity, the pounds per stage, the pounds per foot, what you might be trying there in terms of escalation? And then were the 8,500-foot laterals included in this update? And finally, if you could just refresh me on the net locations you have remaining in your current acreage?

Dan O. Dinges

Okay. I'll take this first on the location size. If you use 400-foot spacing, we are probably over 600 locations. Now we're looking at the downspacing going down to the 300-foot. And as I mentioned, that could add 25% to 30% or so to the location count. On the proppant, I'll let Steve Lindeman have a brief discussion on the proppant question, on what we're doing on a per foot basis, and maybe how we're tweaking some of the proppant size, without getting into too much detail.

Steven W. Lindeman

Yes, just quickly. If we look at our 2013 program, we had pumped a lot of 40/70 mesh sand. In the -- with a 300 -- 400,000-pound range, we've increased our proppant to 30-50, and we've actually done some 20-40 jobs now. And we're pumping about 400,000 to 500,000 pounds per stage on those treatments. And then as Dan mentioned earlier, we are narrowing our spacing from 275, that we had last year, down to something below 250 this year.

Subash Chandra - Jefferies LLC, Research Division

Okay, got it. Okay, and just the final one was if the 8,500 foot wells were included in this update?

Dan O. Dinges

Yes. Some of those 8,500-foot wells were in the 10-well average that I indicated to you.

Operator

Our next question comes from David Deckelbaum with KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Just to clarify, you talked about, perhaps, adding another rig in the Eagle Ford. But the 2015 guidance assumes, on terms of overall growth, that you're using 3 rigs in the Eagle Ford and 6 in the Marcellus?

Dan O. Dinges

No, that's correct.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. And how do you, I guess, balance? You did talk about you haven't done any share repurchases to date. I guess, do you look at, perhaps, putting a rig in the Eagle Ford as a better use of capital than perhaps thinking about share repurchases right now? Or is there -- are they not necessarily mutually exclusive?

Dan O. Dinges

Well, they're not mutually exclusive. However, with the efficiency gains and what we've been able to see with the realized pricing, the Eagle Ford is furnishing excellent returns. And as I mentioned, we have -- and you mentioned, we have 3 rigs running there now. If in fact, we can be successful on additional acreage, we could increase that rig count also, not only for our guidance on '15, but we might be able to do something earlier than that.

Operator

Our next question comes from Brian Singer.

Brian Singer - Goldman Sachs Group Inc., Research Division

This may be repetitive, in which case, I apologize. But your CapEx for the quarter was down a bit and the lowest in a while, and I just wanted to see if you could talk about the outlook for capital spending for the rest of the year? How the Marcellus prices could make that fluctuate one way or the other, in terms of the budget that you have outlined?

Scott C. Schroeder

Brian, this is Scott. We reaffirmed the capital guidance last night, which is 1.375 to 1.475. That plan -- again, there might be some variability within it, but that's still the plan that was reaffirmed 2 days ago, in our board meeting. It's basically a timing difference, just some of the timing and the flow-through of the dollars associated with the completion operation and the drilling operation. We still expect to be within that range. So there'll be -- from where we were thinking, maybe earlier in the year, there's going to be more in the second half of the year. And unless there's some huge dramatic fall off, worse than any of us anticipate, that plan is not going to change.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And that is actual change in activity in terms of the level of spending in the second half? Or that's kind of accounting noise, where you actually probably really did spend more in Q2 than it gets reported for GAAP?

Scott C. Schroeder

Yes, that's accruals. It's accounting noise.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got it, got it. So effectively, you think you're generally on pace, as opposed do you expect some acceleration in your base level spending?

Scott C. Schroeder

Correct.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then I think you mentioned share repurchases in your opening comments. Can you add any more color as to what you would need to see to become more aggressive on that front?

Dan O. Dinges

Well, as I mentioned, we're trying to just dovetail out with the management of our capital exposure, and some of the activity that we are in the middle of, Brian, regarding lease negotiations and acreage negotiations. We wanted to flush all that out and balance with that. And with success or without, they're not, again, mutually exclusive. But we felt like that we wanted to do that, and have some resolution, if you will, on a couple of ideas that we're thinking about, before we jumped out and bought additional shares.

Operator

Our next question comes from Marshall Carver with Heikkinen Energy Advisors.

Marshall H. Carver - Heikkinen Energy Advisors, LLC

Most of my questions were already asked. I do have a question on the downspacing test in the Marcellus. How many additional downspacing tests are you planning for the back half of this year, with the 500-foot spacing? And what are your average well spacing for this year?

Dan O. Dinges

Yes. Marshall, we're going to -- going all the way down in the lower Marcellus to 500 feet. We're going to watch the wells that we have done that close together to see how they perform. We wanted a benchmark that was very close, and we think 500 foot is very close for the Marcellus. But away from the 500 foot, for example, we have a large pad that we are going to drill. And that will -- all of the wells on that large pad will be downspaced less than 1,000 foot. So we do -- and in earnest, we are continuing a downspacing effort, but the 500-foot was a downspaced distance that, again, is going to give us some very, very good data. But I would not anticipate that the entire Marcellus would be able to be downspaced to 500-foot, but I do anticipate it would be able to be downspaced less than 1,000.

Operator

I'm showing no further questions. We will now -- this concludes the question-and-answer session. I would now like to turn the conference back over to Dan Dinges for any closing remarks.

Dan O. Dinges

Thank you, Youssef, and I appreciate all the questions. The questions' fairly narrowed in a band. But again, the takeaway from my closing comments prior to the Q&A, Cabot's going to be able to deliver some good results with our growth -- the production growth, our capital efficiencies. I think you're getting a flavor on what we're going to be able to do with our Eagle Ford operation and -- though it's early stage in what we think we can do with our increase in liquids volumes. But we're optimistic that we're on the right track in that area, and directionally, I think you can anticipate the additional capital will be spent in that particular area. So with that, again, I appreciate the interest in the second quarter call, and look forward to visiting with you all on the third quarter call. Thank you.

Operator

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

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