PDC Energy Inc (PDCE) 2016 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy 2016 second-quarter conference call. As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Mr. Mike Edwards, Senior Director of Investor Relations.

Good morning, everyone, and welcome. On the call this morning we have Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; and Scott Reasoner, Senior Vice President, Operations. Also on the call we have Scott Meyers, Chief Accounting Officer, who, contemporaneously with Gysle Shellum's retirement as CFO, was assigned the duties of Principal Financial Officer.

We've posted a slide presentation that accompanies our remarks today on the investor relations page of our website, which is PDCE.com. I would like to call your attention to our forward-looking statements on slide 2 of that presentation. We will present some non-US GAAP financial numbers in today's call, so I would also like to call your attention to the appendix slides where you will find the reconciliation of those non-US GAAP financial measures.

With that, let's get started and I will turn the call over to Bart Brookman, our CEO.

Thank you, Mike. Good morning, everyone. I know everyone on the call is waiting for our response to the ballot initiatives in Colorado, so I will cover that first and then we will move on to what I consider very positive quarterly results.

I think, as everyone is aware, signatures were due and submitted yesterday for both the setback and local control initiatives. However, based on unofficial reports of the number of signatures submitted and typical validation rates, we believe it is highly unlikely that either of these initiatives will pass the Secretary of State's verification process. This process may take up to 30 days.

Now let me switch over to our quarterly results. An extremely strong second quarter for the Company, significantly beating our expectations, giving us confidence for a positive 2016 re-guide today. Our production continues to perform extremely well and the Company's capital spend levels are improving.

In the Wattenberg field, our operations teams continue to find ways to enhance well performance, particularly with some new innovative completion designs. Scott will cover a lot of this in a moment. And for the quarter, the Company's lifting costs reflected dramatic improvement.

Some highlights for the quarter. Production was just over 57,000 barrels of oil equivalent per day, or 5.2 million barrels equivalent. That is a 54% increase from the second quarter of 2015 and a 14% increase from the first quarter of this year. And our Wattenberg production grew 62% when compared to the same quarter in 2015.

Our operations teams in the Wattenberg and Utica turned in line 37 wells for the quarter. And we once again achieved this impressive production growth and operating activity without a single safety incident.

Some financial results; let me start with operating costs. Our lifting cost showed significant improvement, down to $2.63 per barrel of oil equivalent. That is down from $3.35 per BOE in the first quarter of this year, a credit to our operating teams and their ongoing focus on cost control.

The adjusted cash flow for operations for the Company came in at $113 million and capital expenditures were $108 million, slightly below our expectations. And we are extremely pleased with our per-well cost for our standard, middle, and extended-reach laterals.

Then our balance sheet. Debt to EBITDAX of approximately 1.1 and liquidity at quarter end of just under $800 million. The balance sheet continues to provide the financial strength the Company needs during these challenging industry times.

Then from a business development perspective, we are very pleased with the acreage swap we announced with Noble Energy, which we expect to close in early fourth quarter. This gives PDC a significant and more contiguous block of acreage in the Middle Core region of the field. It provides more opportunities for longer laterals, results in higher working interest in our operated drilling, decreases the corporate non-operated capital budget, and overall improves the Company's capital and operating efficiencies in the Wattenberg field. Scott Reasoner will cover this in a lot more detail in a moment.

Now let me cover the revised guidance for 2016. I am pleased to announce that nearly every component of our business plan is being upgraded. Let me hit the highlights of these adjustments.

I will refer to the table on slide 5. Scott Meyers and Scott Reasoner will give more details around this revised guidance in a moment.

As you look at the table, the PDC logo shows where the midpoints of our new guidance falls in relation to the guidance we provided at analyst day in April. First, production. Our new guidance midpoint is 21.5 million barrels equivalent and our new guidance range for 2016 is 21 to 22 million barrels.

For total revenue, EBITDAX, and adjusted cash flow from operations you can see our new guidance exceeds the high end of our original guidance range. This achievement is complemented by our lease operating expenses, or lifting costs, now being forecasted at the low end of our original guidance range.

And then CapEx. We are happy to announce we expect to achieve these production increases and improve financial metrics, while our capital spend is forecasted at the very low end of our original CapEx guidance for approximately $410 million.

Last, we are achieving all of these positive guidance adjustments while reducing our Wattenberg rig count from four to three sometime this month. This is a direct reflection of the improved drilling efficiencies in our Wattenberg operations, improved performance in our completions, ongoing focus on production optimization in the field, balance sheet strength, and cost control efforts.

In closing, a standout quarter. I want to thank all the PDC employees for their continued contributions. We once again not only met, but exceeded expectations.

Now I will hand this call over to Scott Meyers, our Chief Accounting Officer.

Thank you, Bart, and good morning, everyone. For more details on the material we are presenting today, please be sure to check our second-quarter 10-Q and press release, both of which were filed this morning. I will touch base on a couple of the highlights from the quarter before giving a brief overview of our updated financial guidance for the year.

For the second quarter, sales were approximately $111 million, a 14% increase compared to the $97 million for the second quarter of 2015 and a 50% increase from the first quarter this year. Our year-over-year increase is due to production growth of 54% that more than offset the 26% decline per BOE.

Lease operating expenses, which Scott will touch on more in a minute, came in just under $14 million, or approximately $2.63 per BOE. This compares to just under $13 million, or $3.71 per BOE, for the second quarter of 2015. The decrease in LOE per BOE was largely driven by production growth while lowering environmental and workover costs, while some of the expenditures were delayed until the second half of 2016.

Lastly, net cash from operating activities increased 50% year over year to $97 million in the second quarter of 2016, compared to approximately $65 million in the second quarter of 2015. This growth was driven by our increase in sales and increase in our settlement of derivatives, while maintaining a disciplined approach to our cost structure.

Moving to slide 8, I will highlight a couple of the non-GAAP metrics. Please keep in mind that detailed reconciliation of these numbers can be found in the appendix.

Adjusted cash flow from operations and adjusted EBITDAX can both -- can be seen both on the table and the graphs at the top of the slide. As you can see, both metrics have increased both second quarter over second quarter and sequential quarter to quarter. This is due to our strong production growth driving an increase to our sales, which outweighed the price decline from commodity prices from prior year. Also contributing to the increase is the increase in net settlements related to our 2016 hedge program.

Moving to slide 9 and an overview of our debt and liquidity position, in the second quarter we settled our 3.25% convertible senior notes for $115 million in cash and just under 800,000 shares, leaving us with our $500 million senior notes due in 2022. As it currently stands, we have an undrawn revolver with a borrowing base of $700 million and elected commitments of $450 million.

Including our cash balance of nearly $110 million, offset by our letter of credit, our current liquidity position as of June 30 was just under $800 million when including the full borrowing capacity.

Our hedge summary on slide 10 includes the hedges in place as of June 30. We remain well hedged for the balance of 2016 with approximately 60% of our expected oil volumes and 68% of our expected gas volumes hedged. As you can see, our oil is hedged well above strip at just under $74 a barrel with gas also in the money, averaging approximately $3.45 per MCF. These graphs also show the detail of our 2017 and 2018 hedge programs as they currently stand.

Lastly, a couple of our financial -- a couple of our highlights from our updated financial guidance. As Bart mentioned, we are expecting to produce between 21 million and 22 million BOEs for the year, an approximate 40% increase compared to our 2015 volumes. Scott will give you the drivers for the increase in our guidance in a moment.

In addition to increasing the midpoint of our production range, we are decreasing our expected CapEx for the year to $400 million to $420 million. This is down approximately $15 million at the midpoint compared to our previous range.

Our new adjusted cash flow from operation range is $450 million to $475 million, an increase of $45 million from our prior guidance. This increase is due to increases in our expected production volumes, increased commodity prices for the first six months of the year, expected improved realizations for oil for the remainder of 2016, while maintaining our low cost structure.

With these changes to our CapEx and cash flow expectations, we now project to exit 2016 with a cash balance of approximately $150 million. All in all, we are very pleased with the results from the second quarter and the updated expectations for the full year.

With that I will turn the call over to Scott Reasoner for a look at our operating results.

Thank you, Scott, and good morning, everyone. As both Bart and Scott mentioned, we are very pleased with the way our team executed in the second quarter.

Production averaged just over 57,000 barrels of oil equivalent per day. As has been stated before, that's a 54% increase year over year. In addition to the 37 turn-in lines in the second quarter, we had 34 turn-in lines in March that contributed to these strong second-quarter numbers.

Finally, as Bart touched on, we are planning to reduce our Wattenberg rig count from four to three this month. We are able to drop this rig thanks to increased working interest associated with the expected fourth-quarter close of our acreage trade and increased drilling efficiencies, both of which we will talk about shortly.

On slide 14, you can see several highlights of our second quarter. Our commodity mix for the year is in line with our expectations at 40% oil and 60% liquids. I will note that our oil production of just under 2 million barrels represents a 26% increase over the second quarter of last year and that we still expect to be between 40% and 42% oil for the full year.

Sequentially, our production increased 14% compared to the first quarter and, as I just mentioned, this is partially attributable to the timing of our turn-in lines from the first quarter. Production for the quarter was above our internal expectations.

Our LOE continues to trend in the right direction and our full-year range shown on the graph of $2.85 to $3.15 per BOE represent a reduction of more than 10% from our analyst day guidance. I would really like to commend our operating teams for clicking on all cylinders and pulling off yet another smooth quarter that has driven these results.

Next, on slide 15, you can see the breakdown of our revised capital program. Our second-quarter CapEx came in relatively in line with our first quarter and, for the year, we are anticipating our second-half capital spend to be very similar to our first half. This results in our updated range being reduced to $400 million to $420 million for 2016.

Our well costs have also remained stable, though we are testing a couple of things that may add incrementally to these that I will touch on in a minute.

Taking a closer look at our turn-in line activity here on slide 16, you can see a breakdown of not only the second quarter, but a look at how the first half compares with our expectations for the second half of the year. As you can see, we had no XRLs turned in line in the first half; however, the first batch of these are currently in the clean-up process.

Our Utica program has been moving a little ahead of schedule and three of our five planned wells for the year were turned in line in the second quarter. More on those in a minute.

Slide 17 shows the improvements we've been seeing in terms of drilling and really highlights how far we have come over the past couple of years. When we first showed this slide at analyst day we were projecting approximately 1,900 feet drilled per day per well for 2016, and you can see that in the first half we have exceeded that by more than 10%. You can see we are drilling twice as fast as we were three short years ago and it is because of improvements like this that we are able to operate only three rigs while continuing to deliver peer-leading growth.

I will add that our updated guidance ranges continue to assume an average of 7, 11, and 14 drilling days from spud to spud on our SRL, MRL, and XRL wells. We believe that there may be room for improvement, specifically on our MRL and XRL wells, as we are still relatively early in this process.

Next, we have some new well results with some enhanced completion design tests. The map on the left gives you a sense as to where these pads are located in relation to the acreage map pro forma for the expected closing of the Noble trade. The LDS project depicted in the gray box is a 10-well pad of MRL wells drilled on 20 wells per section equivalent.

Here we tested three different completion enhancements. First, we added various proppant amounts of up to 1,800 pounds per foot, compared to our standard job of 1,100 pounds per foot. We also tested five additional stages, taking us to 40 stages, and lastly, we are adjusting our choke management based on casing pressures. As you can see, these results are extremely encouraging and could be a real game-changer moving forward if the results hold up.

The Sater project is eight SRL wells drilled on 16 wells per section equivalent. Four of the wells were completed with a slick water design. Again, early results are very encouraging and, needless to say, we are watching both of the projects very closely.

Finally, we are able to provide a little more detail related to our acreage trade. Again, this trade is still pending and expected to close early in the fourth quarter. All numbers shown here are preliminary and have not been through the full year-end reserve and location booking process. However, the main take away you can see here is we have increased our Middle Core position.

I will emphasize that we should have the ability to drill longer laterals, which may reduce the number of locations, but would increase the average lateral lengths. Ultimately, we expect to increase the lateral footage we are able to drill in this area.

Additionally, you can see the drop in rig count, and similarly the reduced number of spuds and turn-in lines, for the remainder of the year thanks to the increase in working interest post-trade. Combine all of these attributes with an increase in full-year production and a decrease in full-year CapEx guidances and we couldn't be happier.

I will quickly retouch on the current standing of the proposed ballot initiatives. As Bart indicated, signatures were submitted yesterday for both the local control and setback measures. Unofficial reports indicate that it will be unlikely for either of these measures to make the November ballot.

In the event that these do make the ballot, the industry is extremely organized, sophisticated, and well-funded in its efforts to prevent them from passing. We are confident in our efforts to defeat this initiative and we continue to educate the voters on the negative impacts of these proposals on the state of Colorado.

Moving to Utica on slide 21, I mentioned earlier that the Neff 10,000-foot lateral well came on ahead of schedule. So far, this well is showing encouraging results that we continue to pay close attention to. In our southern acreage block, the Mason two-well pad came online in late June. It is too early to speak to this data, but like the Neff, we are closely monitoring it.

Projected well costs have come down from around $6 million to approximately $5.5 million for a 6,000-foot lateral well. Again, slide 22 gives a little more detail on the program for the second quarter that I will let you go through on your own.

With that I will turn the call back over to the moderator for Q&A.

(Operator Instructions) Mike Scialla, Stifel.

Good morning, guys. I actually had a bunch of operational questions, but I guess I wasn't expecting to be first, so I feel obligated to ask you more about the signature process. What gives you the confidence and anything that you can amplify on there that these won't actually make it to the ballot?

So this is what we know, through two different sources. Obviously, this is not final numbers; but two different means of communication. We believe that the signatures submitted on both 75 and 78 are somewhere around 105,000. Again, that's submitted. And there was one source that it was 105,000 to 110,000, so it's somewhere in that range.

We also know based on talking to people who are experts in this that validation rates generally are going to be somewhere in the 60% to probably low 70% range, depending on if they are volunteer signature gatherers or paid signature gatherers. So when you apply those two numbers together, in our opinion and I think some other people who are pros at this, there is a very, very highly-likely scenario that they will not have enough valid signatures, which they need 98,000. So if you do the math, we believe that they will be well short of that 98,000.

But I think it's very important to Scott's point, as of this morning, PDC and the industry is treating this as though they have submitted the signatures. Our campaign continues. You can expect this to be full force until we get final verification from the Secretary of State's office that they do not have sufficient signatures.

We are funded and organized. This will be a collaborative effort. Then, even if they announce they don't have sufficient signatures, expect the industry to continue with our mission, which is to first communicate the safe aspects of oil and gas development in Colorado and, secondly, the importance to the state as far as job creation and the economic benefits of the oil and gas industry within the state.

So our mission will not slow down on this, Mike. We will continue to try to educate our voters about the importance of oil and gas in the state of Colorado.

That sounds good. Wanted to ask on the plan to reduce to a three-rig program. Obviously, taking your 2016 guidance up; could you talk, even generally, about what impacts that might have on 2017? I think at analyst day you gave some preliminary production guidance for 2017. Will that reduction have any impact on that?

Good question. Based on what we know right now, no. We will enter 2017 obviously with the three rigs running. We have not put our capital budget together for next year.

I think Lance presented several scenarios. Most of those had a 20% to 30% production growth. I think those are reasonable ranges still, even with the three rigs and some of the drilling efficiencies that Scott just covered, so I think the market can expect us to strive for those type of numbers.

What we've got to do is take the Noble swap; the change in working interest; the success of longer laterals; the new completions, particularly the LDS pad that is, in my opinion, incredibly impressive; and take all of that, run it through our budgeting process. And then our commitment is I think we will strive for peer-leading growth, continued focus on the balance sheet, and continued focus on our costs, which we were extremely pleased with. So I don't think there is anything that should scare you off of what Lance presented at analyst day.

That's good to hear. Last one for me. Just looking at slide 17, some pretty significant progress there on the drill times. Just wondering if the longer laterals, extended-reach laterals if you are using the mono-bore design for those or is that another potential timesaver as well?

Mike, this is Scott. We began doing the mono-bore in the second quarter, maybe even late first quarter, and have seen good results in all three different wellbore configurations -- lengths is maybe a better way to put that -- and we expect to continue through that. So some of what you are seeing there in that 2,200 feet is mono-bore in all three lateral lengths.

We still feel like, though, with what we've been doing there's room to get better. And that's particularly on that middle lateral and extended-reach lateral, I would say, are the two with the most likely room to move, particularly relative to our 7, 11, and 14 days that we've still got in our budget for the rest of this year.

Great. Good quarter, guys. Thanks.

Steve Berman, Canaccord.

Thanks, good morning. Slide 15, the $2.5 million, $3.5 million, and $4.5 million well cost, is that where you are now or is that still -- is that a slide that -- I'm just wondering how much more can you sneak out of those numbers. I know you are early in your XRLs, but any color there is helpful.

The question, in case everybody couldn't hear that, was where are we at in our $2.5 million, $3.5 million, and $4.5 million cost structure on slide 15.

We are really sitting in the middle of those. I would say the firmest of those is the SRL. We don't see a lot of movement off of that one. There may be a little bit of movement there, but not a lot.

When you start talking the MRLs and XRLs, we feel like there's still room to move. The discussion we just had around drilling and the opportunity to maybe take a day off here or there on both the MRLs and the XRLs is a part of that. Then also, I would say we're still working through the completion methods, the completioning process, and I think our guys will get more efficient on those as well.

So a little bit of room to move on both of those. But as I said, if we add sand, additional sand to these wells, that type of thing, the cost structure could increase as a part of that. So depending on where we land on each one of those different processes we've talked through -- the additional stages, additional sand, and the slick water jobs -- that could influence the cost structure as well.

Got it. Then moving to the Utica. Oil gets most of the press, but natural gas since earlier in the year has moved up very nicely. What would it take you to get more active in the Utica, especially if the [message is] (inaudible)?

I'll jump on that. Here is kind of a high-level viewpoint. We are still hopeful that in 2017 we can have a drilling program in the Utica. We are still evaluating our Neff and our Mason pad. Our Miley pad I think is scheduled to come on late this year; waiting on pipeline connection there.

The big picture is we are very pleased with some early results on these recent completions and our cost structure has improved tremendously, Steve. I think we are down on our -- at $5.5 million on our 6,000-foot laterals, and I think we are probably in that $7.5 million range for a 10,000-foot lateral. We do believe that the 10,000-foot lateral is the current way to go to optimize your capital efficiency in the play.

And then I think cost structure, plus an oil price near -- and I think this is consistent with what we've been in the market with -- an oil price near $50 or higher and a gas price holding around $3 in M, the economics of the Utica start to hunt with let's call it an Outer Core/Middle Core mix of the Wattenberg. And those are numbers that we don't think are unreasonable for next year, based on some internal forecasts.

So we are not that far away is the bottom line. But, obviously, this last month we have been watching the oil market; I think it's been a little discouraging to have it curl back where it is. But our forecast is still -- as we go into next year, we expect a modest rebound, probably back up around 50, maybe a notch just above 50. So, hopefully, I answered your question.

Neal Dingmann, SunTrust.

Morning, guys. Bart, how are you thinking -- obviously now doing that first extended reach, it looks like on that the slides you had the dots we're doing about maybe 1/8 of the total. Is that just sort of time will tell, kind of see what the uplift versus the cost is there to see how that will translate in -- the XRLs into the 2017 plan?

Hopefully, I got the question, Neal. I am a little bit confused about where you are headed with the question. If you could just tell me a little -- are you talking about Wattenberg or Utica?

The Wattenberg. It just looks like I was looking at one of the prior slides, not necessarily from today, but kind of where you talked about how much of the extended reach obviously you were doing this year. It's certainly a relatively small amount of the total.

So my thought is: for 2017, is it sort of well-dependent on how those results look? Could you end up doing half extended reaches next year now that you've done -- traded some of that acreage? Or how are you thinking about the extender reaches next year?

I think when you look at our picture overall, we will -- that acreage swap absolutely adds to the number of longer laterals that we can drill; that consolidated acreage position will allow for that. In terms of what we are looking for next year, I am not really sure yet, but obviously the pressure will be toward more longer laterals with that whole trade happening.

In terms of the economics, we still see the economics, with the way we have laid them out in our past slide, competing between the three different lateral lengths. But I do believe the middle laterals and the extended reach laterals both have more upside to their economics than the standard laterals do. Some of that because of cost, some of it because of the choke management process and the additional stages that we are talking about. I think we just don't have as much data on either one of those groups of wells, but I think there's more upside to both of those.

So we are going to be moving full force forward, if our land position justifies it, with drilling longer laterals. I appreciate you clarifying the question; I understand what you are looking for there now.

That was great detail. And then, Scott, for you or Bart, you guys have done obviously an excellent job of blocking up a lot of that acreage. So you can do the longer laterals. Are there additional opportunities there, or perhaps even in the Utica, to block up more of that acreage?

Neal, this is Lance. We continue to look at good, solid sort of win-win trade opportunities, especially in the core Wattenberg, whether it's a few sections or whether it's 5,000 to 10,000 acres, that makes sense for the Company. Because obviously, in doing that, the blockiness brings typically higher working interest and longer laterals and more synergies for both parties.

It's a win-win proposal, so it's something that companies like to have and it really just gives a lot more clarity for the ability to have a higher working interest and higher operations going forward. So that's something that we will continue to look at and continue to pursue.

That makes sense, Lance. Then lastly, Bart, just on M&A; when should we look to you guys to do the next big deal?

Thanks for the entertainment, Neal. We have been consistently in the market that we entertain deal flow; that we are looking for quality deals, comparable projects, return wise, to the Wattenberg. That results in an incredibly select process for us and we are being incredibly patient, Neal, so obviously nothing to talk about.

Lance, you want to add?

We've done a good job outlining in our April analyst day all the different factors that we looked at as we consider potential acquisitions, and so it's got to mean a lot of hurdles for us to consider and to pursue it. But, anyway, we outlined that at analyst day. And so thanks for the question but I think we have already talked through a lot of that.

That makes sense. Thanks, guys, so much.

Jason Smith, Bank of America.

Good morning, everyone. Congrats on the results and I appreciate the color, particularly on Colorado.

My first question, just a follow-up on one of Neal's questions. You've talked in the past about getting ahead of permits, so I'm curious, given the Noble asset swap coring up your acreage, are there any potential permit issues if you shift from, let's say, a standard-length lateral to an extended reach.

A lot of nuances to that question. It's a very complex project, but at this point our teams are working diligently to first close this deal, because it's still a pending deal, but at the same time looking for opportunities to begin the permitting process.

Some of the permits will be extensions of our existing permits and that's a little easier process. Where we add a half-mile or an additional mile to an existing permit, that's a little bit easier. Where we see the opportunity to go to two miles where we may have had two one-milers go in opposite directions or something like that, that will require new permits. And so our teams are working through that.

They understand that we have to have the flow of permits next year for the three rigs that we are moving through the system with. At the same time, they understand that we want to do all we can to drill longer laterals. And that's a typical position we put our folks into where they have to keep those judgments -- both those judgments in mind: doing all they can to make those adjustments, at the same time keep those rigs running.

So I would say, as I've said before, that we plan to drill longer laterals and our team will do everything that we can to make sure that happens. As you would suspect, they will be as effective as possible at that and I think they are ready for it. They really just need to be able to close at this point.

Thanks, Scott. Then on the LDS project, I guess you guys mentioned in the slides a 15% to 55% increase in proppant. And I understand it's still early, but just is there a certain point where you are seeing diminishing returns at this point?

And I guess what I'm also trying to get at is what level of increase you guys are looking at as kind of a standard-based design going forward?

That's a great question; I don't really know if I can answer the last one. We really need to see the data from the testing we've done.

We've run -- the 1,100 is our standard of the past. The 1,350, 1,850 range per foot is what we've used in the test in the LDS. Early in that process we don't see a lot of difference between the 1,350s and the 1,850s, but we really are expecting that to come a little later in the production process, so we really need to see the data from that.

Going forward as we -- and I guess the best description I can give you is there's a fairly significant cost associated with adding sand and it ranges from $0.25 million to $0.5 million, let's say. Someplace in that range depending on how much sand you add. So we are obviously wanting to see the results from the money we've already spent.

As far as what we are planning to do with those LDS results, because they are very, very inviting for more of that same type of work, we're looking at definitely going forward with our choke management process, which adds little to no cost. It is personnel-based; our guys watching those wells more carefully. And then secondarily, adding additional stages does not add a lot to the ticket, the frac ticket.

So we're looking at those two things first and then as we see the result, a little more data from the additional sand, we will make that decision. I do know there are different parts of the world you see this regularly, where sand concentrations continue to go up. We are watching that as well, because obviously many of those groups are working in similar shale plays.

Thanks, Scott. Appreciate all the color.

Michael Hall, Heikkinen Energy.

Thanks. I just wanted to follow up a little bit on the LDS product actually. Just curious philosophically, as you look at the results from that initial pad that appear to be outpacing the core type curve, the MRL type curve, how do you think about further downspacing in that context? Does this give you more confidence to keep pressing on the downspacing, or do you think you are at a relatively optimal spacing and you just take the well outperformance? Just philosophically trying to think about how you guys look at that.

That's an interesting question and probably something we will be looking at for quite a while would be my best answer to that. But I will step back a little bit to what we showed at analyst day and really we feel like that 20 to 24 range is a good number yet from everything we've seen. I think the issue that I still have with LDS is that data is very early and we could still see the decline increase over what we are showing on a typical type curve there. So we will be watching that to see what that looks like.

This may be an area in particular -- and if you note where it is, it's right in the middle of that trade consolidation area, I should say maybe more on the edge, but it's in and amongst that acreage that we traded for. So we really like where it's headed and we definitely want to take advantage of it, but I do think it's a little early to speculate on how many more wells we could add. If that decline curve flattens out nicely parallel to our type curve, we could see -- you could see us questioning could we add more wells I think. And I think that's your point as well.

Okay, that's helpful color. And then, given that you don't have -- you haven't brought the XRLs on yet, but you've got some in the back half, I'm just curious how have you guys -- can you remind me how you've risked that production within guidance and --?

Our type curves on those XRLs are 850,000 barrels of oil equivalent and much of that data is based on our peers. As you've said, we don't have any XRLs on ourselves. Oftentimes we are dealing with the older data from our peers because that's the data that has the most months of production associated with it, so some of that is a bit dated.

So I think that, as well as the way we just basically shifted up -- if you look at the MRL type curve and the XRL type curve, it's just a shift up. If what we are seeing is true in these MRLs with the additional stages, the additional choke management, the additional sand is true and we can adjust that curve up somewhat on the MRLs, we feel like we can do something similar on the XRLs.

There is a lot to that, but there's also an added length in our XRLs that's not accounted for in that 850,000 barrels of oil. Some other things that are details that we can talk about for quite a few hours; we debate them constantly here. But the proof in the pudding is truly getting the data from this first batch of XRL wells, which are, fortunately for us, coming on earlier that what we had planned because of some of the work our team did early this year to get some longer laterals going.

Okay, great. Can you remind me when the exact timing on the turn-in line is expected on those?

We are in the process of cleaning those up, so I would say in the -- I'm giving myself a month. But I would say in about a month or so, a month and a half maybe, time to get all the wells cleaned up and ready to produce.

Great. Then last one of mine, I guess just on the ballot stuff, for lack of a better word. Are you guys grandfathered on existing permits or --? Like, if this was to go through in November, let's just say, in a bear case scenario and I imagine it gets caught up in the courts in the interim, are you grandfathered with the permits that you have? And how far out do you have permits at present?

The easiest answer that is, based on what we see and the way that was written, no, we won't be grandfathered in. So the number of permits that we have is inconsequential. At this point we have enough permits probably to get us through next year or close to the end of next year. And so the way we read that and the way that's written is it would not allow us to grandfather those permits.

Okay. Well, here's to not having to worry about it.

We're with you.

Thanks, guys. Appreciate it.

Welles Fitzpatrick, Johnson Rice.

Good morning. Thanks for the details on 75 and 78, but a big knock on wood, if those do end up not having enough signatures, is the industry going to continue pushing on I believe it's 96, the 2%, 55% rule, so this isn't a repeat in 2018 and 2020?

Thank you, Welles. Actually a great question and the answer is yes. We have a lot of confidence and a lot of support around what we call raise the bar. It is 96? Okay. That will most likely be renumbered when this all gets said.

We have submitted the signatures on that effective last Friday. I can assure you, based on the number we know, which I don't think I'm at liberty to reveal, there are sufficient signatures to put that on the ballot. So you are going to see a significant, funded campaign around that.

And just to inform everybody on the call, that is a ballot initiative where there's a more equal distribution amongst all of our senate jurisdictions across the state for signatures on a ballot. So you can't go to one focus area to gather signatures; you need to have those signatures from across the whole state of Colorado. We believe that is better representation by the voters within the state.

And then it also takes a 55% voter approval rating on any ballot proposal. We believe that is a much more stringent and fair way to give consideration to amending the constitution in Colorado, which I believe the past couple hundred years we've had like 150 amendments to the constitution.

So some of this is, in our opinion, ridiculous; having the out-of-staters come in and use this as a platform, making their proposals from out-of-state opinions, hiring out-of-state people to come gather the signatures. And Raise the Bar, we believe, is going to really change that process. So it's very important in this whole ongoing battle that we have going on.

Perfect, thanks so much. That's all I had.

Michael Glick, JPMorgan.

Morning. Just a couple questions on the new completion tests. You mentioned adjusting your choke management on the upsized completions. Can you just give us a little bit more color on what you are doing differently there?

Sure. I think the best way to describe this is that we are taking our standard-reach laterals and paralleling -- trying to parallel those pressure declines. And I'm going to simplify this for the whole discussion, because I'm sure our teams have a much more complex process they go through.

But trying to parallel our MRL pressure declines on the backside with our SRL-type wells and we will do the same with our XRLs. Really, that's the basics behind what we're trying to do. Getting that fluid moving earlier.

Obviously lifting those early time volumes will help our rates of return, if that -- and hopefully we don't -- we don't think it will, but if that does in some way impact our productivity on these wells. So really that's what we are doing.

Got it. Then is there anything else you are testing that could further drive productivity, like combining sand and increase stage of the slick water?

We did do on that Sater pad that was on that slide with the LDS, we did some slick water tests. You can see the data and it's really -- that graph is even hard to tell -- in my mind it was hard to tell -- to see the difference between the hybrid and the slick water jobs. But we will keep watching those slick waters to see how they perform.

I know there's a lot of effort in much of the industry and particularly in the Wattenberg; many companies are going with slick water at this point. We've tried some of those in the past and have not had the best of success.

But things change in the way they are executed, the rates you pump at, the kind of chemicals you include. The surfactants particularly can influence the outcome. So there are different potential outcomes than what we've seen in the past and that's why we keep moving forward with these tests.

All right, thank you very much.

This is Bart. Let me just jump back to Welles' question, I just received notice that there is a press release on the Raise the Bar initiative. And that -- just to put this in perspective, when you're talking about signatures submitted, the Raise the Bar campaign had 185,000 signatures submitted to the Secretary of State. So you can compare that to that 105,000 number.

Again, you need 98,400 and some valid signatures to be on the ballot. So it gives -- Welles, to your question, it should give you some confidence that the Raise the Bar, in our opinion, is going to be on the ballot.

Brian Corales, Howard Weil.

Good morning, guys. Couple questions. On the -- is there any -- I know it was really early on the Mason pad in the southern Utica. Can you give us any more details, maybe how it's comparing to expectations or how it's comparing to other wells in that general area?

At this point, Brian, we are obviously watching that very carefully. What we are seeing is we're still early in the flow back process, so we are making quite a bit of water, and with that we really have to wait until we start to see that cleanup process further into the life of that well. And that's really what we've got to hold our, I guess our excitement or lack thereof, depending on how that turns out, until we get that data.

The other part I will say, though, is it's critical for making the decision on the acreage extensions for next year. We realize that and that's one of those things that we're looking at closely, because we will have -- as we've talked before, we have a significant amount of acreage that's got to be renewed next year. And it will help us make that decision as to how much we renew and what we are willing to pay in order to renew it.

Okay. And maybe, Scott, it's three months from now to the November call, is that when you will probably give some kind of details?

I would think there's a good possibility, but I wouldn't want to be held to that completely. So give me a pass if I don't give you any update on it next quarter, too, would you?

I will ask you again, though. (laughter)

Understood.

And one more. You all did a great job on the operating cost side. Is that service cost -- is it just service cost deflation or did you all do something that drove that?

Really two major contributors, Brian, to that. One is we had continued staffing that we were planning to add with our production growth, the number of wells we are adding, particularly in the field operations group that impacts the LOE side of this. And we delayed that because of the low prices.

So part of the reason we are not as low as what you are seeing on that second-quarter number looks like in terms of our guidance is we are planning to go forward with prices stabilizing, I guess you can call it, although we wouldn't call it completely stable yet. But prices stabilizing. We are going forward with hiring more of those individuals so that is going to put a little upward pressure in the second half of the year.

Then we delayed a fairly significant batch of workovers. Really, I say delayed, but we really didn't have a lot of ones that we wanted to go get done is really the way we look at it. So we've just decided, because of the economics, that we would hold on those and at some point in the future we may actually do them. But at this point we are really putting those on hold and don't expect a lot of those in the second half, although some of them may get done.

That's helpful. Thanks, guys, and good quarter.

David Deckelbaum, KeyBanc.

Morning, Bart and Scott. Thanks for taking the question. Curious as you look at the Noble swap and your plans for 2017, you talked about -- I know it's a little bit early to be piecing everything together. But I guess just given how blocky the acreage is now, should we expect to see a noticeable improvement in terms of downtime for offset operated activity?

That's a great question and, yes, the answer is we can orchestrate that better if it's our own operations in terms of how that's done. So our existing horizontals will not have to be shut in, because we will be drilling them in a very orderly cadence, in a very orderly situation. And I guess that absolutely doesn't -- you have less downtime associated with that is the best way to say it.

So really that will help us. I also think, when you start looking at that whole cycle of how we drill and how we turn in-line wells, we will have much better orchestration of that process because it is blocked up acreage and we control the outcome, the process. And so I think it's going to help us on all fronts.

I appreciate that. Then, Scott, I don't know if I missed this, but just going back to the LDS pad, did you give an indicative increase in well costs for that type of design with the increased proppant loading and tighter stage spacing?

Yes, I did, and the answer was about $250,000 to $500,000, most of which is for sand. So it's not an inconsequential increase when you look at it in a percentage of the overall cost of a well, but it is something that you can see that uplift in production is significant.

And so, like I said, the least expensive part of that is choke management. The second least is the additional stages and the most expensive part of that is the additional sand. We will be looking at that process very carefully and understanding what that means, but be pushing on the first two parts the most to see what that means.

And then we do have that 1,350 and 1,850 or 1,800 pounds per foot test that we did in that area. Be looking at the two of those to see if there is some separation in the future.

Okay. How many more similar tests do you have planned currently or are you still collecting data on the first?

Really, call them tests of each one of those different parts. Our guys are looking at those results, as you guys are I'm sure, and are excited about those. They will be, I would say -- maybe not every pad that we have going forward, but many of the pads will at least try one of those different techniques and maybe a combination of a couple of them.

Thanks, Scott. That's all for me.

John Nelson, Goldman Sachs.

Good morning and congratulations on putting up a solid quarter. Scott, you mentioned in your prepared remarks you still have confidence in the full-year 40% to 42% oil mix guidance. You're running a little bit below that in 2Q.

Can you just help us maybe bridge how you still expect the Company to get there?

Sure. In the first half of the year, many of the wells that we turned in line were in the Inner Core. And a couple of comments about those Inner Core wells.

Our oil production is right on our expectations. We are right where we wanted to be there. Fortunately for us, the gas is outperforming so that GOR is a bit higher in that particular group of wells that we turned in line, and as we described before, there's variability across each one of those: the Middle, Inner, Outer Core. We just happened to get in a little bit higher GOR area when we turned those wells in line.

That really pushed our gas volumes up with, like I said, our oil right where we expected it. As we move through the year, we are moving to the Middle Core, so we have turned on many, I'll say most, of the Inner Core wells at this point. We're moving to that Middle Core, where we have more typically that GOR is a step down, and we will be expecting the oil volumes relative to the gas volumes to come up.

But, again, our numbers still -- with everything we see and the modeling we've done, we still see those numbers coming in that range that you talked about.

Okay. Is it fair to say the low end of the range is probably more realistic or do you still feel kind of good overall about the top and the bottom?

I don't know if I can answer it more precisely than I have. I will say if gas continues to outperform in that Inner Core that's going to make it more challenging, because that gas is something that I'm not sure we fully baked into our plan through the rest of this year. It's probably partially baked in.

That's fair. Then, as my follow-up, are there any large -- as we think about the Noble acreage swap, are there any large infrastructure needs that you think you'd probably want to build out kind of into the field or have built out into the field early next year, such that really getting active on the acreage might have some bit of delay?

We're giving that very strong consideration right now. Fortunately, our midstream team has done a great job of getting us connected via oil and gas pipelines, so more and more our oil is being delivered via pipeline where we have trucked it in the past. I'm sure we will continue to pursue that; it makes our field operation smoother.

It also is a much easier route in terms of the environmental impacts and all that. Fewer trucks, that type of thing for our neighborhoods that we work in out there. I know our farmers, etc., really appreciate the idea that we are reducing the truck traffic in the area.

The other part of that that we're looking at is water. Can we put in water lines, both for supply water and disposal water? And that's something we're looking at. Obviously that trade is fairly new, but it's one of the things that excites us about the future. We feel like there is opportunity to do those kinds of things and make our operations that much more efficient.

We really haven't settled on doing any of that yet, but it's something we are giving strong consideration for and part of the reason why we conducted that trade.

Great. That's all I had. Thanks, guys.

David Beard, Coker Palmer.

I appreciate all the work you're doing on completions and that you still have in front of you, but I know you talked about downspacing into the mid-20 wells per section. Do you have any plans to test up that high at all when you look at next year?

We really don't at this point. We feel like we're -- as I said at analyst day, we have settled in on that 20 to 24. It doesn't mean we won't.

But I think a lot of our focus right now is optimizing that acreage that we have traded for with Noble and really getting that understood, getting the maximum number of footage -- the maximum footage per well figured out. Getting that all in place is really our focus for this short term.

Will we consider some of that? I think there are definitely results that we will look at over the next several months from some of the wells that we've done in the past, as well as some of these that we're trying currently, the LDS being one of them, that might push us that direction. You do get into a lot of complexities in trying to place wells, though. And I've said this all along, the surface possibly restricting us, but more importantly, the vertical wells become -- we've got to have pathways that are clear to put wellbores through. So all those factors play into the decision on how many wells to put in a section.

Good, thanks for the detail. Then shifting over to the acquisition question, let me ask it a little bit of a different way. Would you consider share buybacks as a viable alternative to acquisitions? And maybe, if so or if not, why?

David, that's probably a concept I haven't thought about in a while so thanks for opening up that part of my brain. I think my initial reaction is no. We really -- our balance sheet strength, our liquidity right now --.

I think accelerating our capital programs, pursuing peer-leading growth, maintaining that balance sheet strength over the next 12 months, and then, as Lance described and I described, an incredibly selective process on the business development, I think that is our best strategy we have right now versus buying back shares. We just went to the market here last March on our offering, so I think the market might receive that as a little bit of a changeup or confusion. But appreciate the question.

Thanks for all the color and congratulations on the quarter.

Jeff Robertson, Barclays.

Scott, question on the trade, a follow-up to several comments earlier. Are you prepared yet to talk about any material improvements with the cost structure, either on operating costs or some of your marketing arrangements or price realization that you might be able to achieve with a much blockier acreage position?

That's, again, a part of why we looked at this project. Obviously, as you -- if we can put infrastructure in place, we are going to be looking at the economics for that infrastructure no different than we look at the economics of our well to make sure our economics justify the investment.

When you start talking about what those numbers are, I think we are still really early in all those assessments. As I've said before, as I said a few minutes ago, Lance's team on the midstream side has done a phenomenal job getting us connected to oil markets via pipe and via trucks that are really pushing our differentials down. And Lance may have comments on that.

But I can tell you, all of those steps just make us that much more viable as we go forward. We've got a definite need to make those adjustments; I just don't have a number at this point and really don't have a feel for what that can be until we can lay out the structure of the pipe. For instance, if are doing water disposal pipe is it reasonable water -- a reasonable fresh water pipe? Either one of those.

We really have to lay that pipe out with this acreage in mind and make sure we've got reasonable rights-of-way, etc., and all of that is yet to be done.

Does that process just take -- I guess it's an evolving process, but do you think just by the time you get to next spring and maybe reporting year-end and it closed and looking to have your definitive plan for 2017 you'll have a little bit better view of where the benefits lie or where the costs lie, rather?

I think that's a fair timeframe. I would say come analyst day timeframe next year hopefully we have more of this figured out. Obviously, the deal will be closed by then and we will have more management of that and understanding of that position. I think at that point we will at least have a flavor for where we can take this.

I really -- we've got a lot of folks, a lot of team members looking at that trying to figure out how can we make that all work.

Okay, thank you.

Irene Haas, Wunderlich.

This is Vedran Vuk filling in for Irene Haas. Just had a question on the Utica well cost. Is there some more room to push those down further? And are there some completion design tests that you would like to look into there, maybe putting more stand per lateral foot and such?

The short answer to your question is yes. When we look at the well costs, we are still faced with individual wells on -- one or two wells on a pad instead of full development of a pad. And with that comes obvious cost savings: the location build is spread across more wells, water management becomes more efficient, both the supply water and the disposal process. We've got the opportunity to benefit from a frac crew rigging up one time, a rig rigging up one time, on a location. All of those things are definite cost-saving measures.

In terms of the completion side of things and what we would do, our teams have a number of other things yet that we consider. We've tried very short stages. We've tried a little bit longer stages, greater sand concentrations and less sand concentrations, and really each one of those we are watching carefully to determine what the next steps will be as we look at drilling for next year.

Do I have an absolute direction that we are going at this point? No, because really what we want to see is how the Neff and the two Mason wells perform. I think Bart pointed very clearly toward the idea that longer laterals are much more efficient and the economics of those look to be much more -- a much better number associated with them than the 6,000 footers. So, if anything, our teams are looking at 10,000 feet-plus. I'll say they may still have some 9,000-footers in the queue here, etc., but looking at that range of length of wells is a part of next year's program. Again, Bart's point around making sure that we understand the economics of those is really where we are at right now.

And how much sand are you guys typically using right now in the Utica completions?

I hope I can give you a clean answer on that one. I'm not sure if I can answer that one. If you will, I will ask Mike Edwards to get back with you on that, if you don't mind.

Great. No problem and great quarter.

I'm not showing any further questions at this time. I would like to turn the call back over to Bart Brookman for closing remarks.

Thank you, Kevin, and thank you, everyone, for joining the call today and the ongoing support and the great questions. Look for more quality results from the Company going forward.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.