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Edited Transcript of BBG earnings conference call or presentation 3-May-17 2:00pm GMT

Thomson Reuters StreetEvents

Q1 2017 Bill Barrett Corp Earnings Call

DENVER May 5, 2017 (Thomson StreetEvents) -- Edited Transcript of Bill Barrett Corp earnings conference call or presentation Wednesday, May 3, 2017 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Larry Busnardo

* R. Scot Woodall

Bill Barrett Corporation - CEO, President and Director

* William M. Crawford

Bill Barrett Corporation - SVP of Treasury & Finance

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Conference Call Participants

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* Brian Michael Corales

Scotia Howard Weil, Research Division - Analyst

* David Earl Beard

Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst - Exploration and Production

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst

* Gabriel J. Daoud

JP Morgan Chase & Co, Research Division - Senior Analyst

* Jason A. Wangler

Wunderlich Securities Inc., Research Division - SVP and Equity Analyst

* Welles W. Fitzpatrick

Johnson Rice & Company, L.L.C., Research Division - Associate Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation First Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to turn the conference over to Larry Busnardo, Senior Director, Investor Relations. Sir, you may begin.

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Larry Busnardo, [2]

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Good morning, and thank you, for joining us today for the Bill Barrett Corporation's first quarter 2017 earnings conference call.

Joining me today are Scot Woodall, Chief Executive Officer; and Bill Crawford, Senior Vice President, Treasury and Finance.

Before we begin the call, I encourage you to read the disclosure statements provided within the forward-looking statements of our earnings release, which has been posted to the homepage of our website at billbarrettcorp.com. You can also find and review these disclosures as they are referenced in our other filings with the SEC or in our 10-Q, which we filed yesterday afternoon.

In addition, we will be referencing non-GAAP financial measures during our call. You can find a reconciliation to GAAP financial statements at the end of our press release.

And with that, I'll turn the call over to Scot.

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [3]

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Thank you, Larry, and thank you for joining us today to discuss our first quarter 2017 financial and operational results. I'll spend some time reviewing our operational results and outlook before turning the call over to Bill Crawford to review the financial results.

We executed on our operational plan, and our first quarter results demonstrate that we are off to good start to 2017 and on track to meet our operational objectives. The quarter was highlighted by production being at the high end of our guidance range. Lease operating expenses in G&A that were significantly below the first quarter of 2016, improved oil price realizations that were driven by tighter DJ Basin oil differentials, as we exhibited continued capital discipline as capital expenditures were below our guidance range. In Utah, we have renegotiated our oil marketing contract that will lower our oil differentials to below $2 a barrel beginning on May 1.

Consistent with our strategy of maintaining balance sheet flexibility, we recently pushed our nearest term maturity with the issuance of senior notes due in 2025. The proceeds, plus cash on hand, will be used to redeem our current notes due in 2019 and extends the timing of our nearest maturity to 2022. The reduction in debt and related extension positions us better financially for the future.

Bill will discuss these matters in more detail in his prepared remarks.

Overall, it was an excellent quarter of execution by our operations organization and our entire organization and provide a solid foundation for the year. During the quarter, we opportunistically added to our DJ Basin acreage position, as we were issued a 2,900-acre federal lease under the Riverside Reservoir for a very minimal purchase price. We are pleased with the acreage addition, as it is located in the central and southern portion of our acreage and is contiguous to our existing acreage.

We're in the process of forming a drilling unit under this acreage to facilitate development. This acreage will add up to 50 extended reach lateral drilling locations to our inventory that is prospective for the Niobrara B and Niobrara C formations.

Since the beginning of the year, we have added nearly 17,000 net acres in the Northeast Wattenberg through similar type transactions. As I've outlined in the past, our strategy is to opportunistically expand our core acreage position, and we will continue to pursue other opportunities as well.

Now turning to operations. We are off to a good start to the year and on track to execute our 70- to 75-well program in the DJ Basin. As previously announced, we plan to add a second drilling rig in the DJ Basin during the second quarter that will further accelerate drilling activity.

DJ Basin production averaged 14,200 barrels of oil equivalent per day in the first quarter, which was 22% higher on a year-over-year basis. We expect to deliver a company-wide increase of 7% in our 2017 volumes, and our position for growth of 30% to 50% in 2018 with even higher oil volume growth, as we deploy increased capital to ramp up drilling activity during 2017.

Our capital program is fully funded by our cash on hand, and we expect to end this year with a cash position and nothing drawn on our bank revolver.

Although the first quarter was quiet from an operational news standpoint, we were very active from an operational perspective, utilizing 1 rig during the quarter to spud 5 extended reach laterals and 9 mid-length laterals. In addition, completion operations were finalized on 13 wells that were placed on initial flowback during the quarter. This includes 4 extended reach lateral wells located in the Section 4-62-20 and 9 extended reach lateral wells located in the section 5-62-27.

We also plan to initiate flowback on additional 14 wells during the second quarter. This will contribute to what is expected to be an increase in production profiles through the second half of 2017 and translates into a significant increase in volumes in 2018 as outlined by our guidance.

We maintain complete flexibility with respect to our drilling program, as we do not have any drilling leasehold or marketing commitments, allowing us adjust our capital program very quickly, if necessary, to adapt to changing market conditions.

The improvements in our completion design continue to evolve and are now substantiated with production history and actual results. With 2 years of production history, we've observed a 36% improvement in the cumulative production for wells utilizing 1,200 pounds of sand per lateral foot when compared to wells utilizing 1,000 pounds of sand per lateral foot.

Additionally, a comparison of wells with spacing of 120- feet per frac stage compared to 170-feet spacing per frac stage indicates a 10-plus percent improvement based on the first year of cumulative production. Our 2017 completions will build on these results, as our base design for the year will include 1,500 pounds of sand per lateral foot and frac stage spacing between 100 and 140 feet.

We are pleased with the early results of our enhanced completion program, including the higher profit concentrations and tighter frac spacing, and we anticipate that well performance and recoveries will improve as we implement these changes more broadly. So a great job by our operations team in achieving these results.

Our 2017 program provides an attractive investment opportunity on our base assumptions and is expected to generate rates of returns of greater than 45% at the well at current pricing, at current strip pricing. As we continue to optimize our enhanced completion design and focus on our efficiencies, we expect to see improvements in both well performance and our cost structure.

Lastly, we're in the process of finishing up a 9-well recompletion program in the Uinta Oil Program that will begin producing in the second quarter.

In summary, we are positioned to deliver on our operational objectives, and we've retained a meaningful cash position with ample liquidity that puts us in a good financial position to execute our development program.

I would now turn the call over for Bill for further comments on the financials.

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William M. Crawford, Bill Barrett Corporation - SVP of Treasury & Finance [4]

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Thank you, Scot. As Scot mentioned, we are off to a great start to 2017 with the first quarter providing a solid foundation for the year as we posted solid results that generally exceeded guidance and sell-side consensus estimates. The outperformance was largely driven by production coming in at the high end of our guidance range, continuing improvement in our cost structure and higher price realizations, all leading to top-tier basin operating margins.

I'll now spend a few moments going over some of the highlights for the first quarter. We generated discretionary cash flow of $23 million and EBITDAX of $36 billion, all above consensus estimates.

Quarterly production volumes of 1.43 MMBoe were at the high end of our guidance range, and consistent with our internal forecast, volumes had a slightly higher natural gas weighting than previous quarters at 58% oil, 22% natural gas and 20% liquids. This was primarily the result of not having any new XRLs completed in the latter half of 2016. We expect second quarter 2017 oil weightings to be slightly higher and average 60% to 65% for the full year, as we bring on the new wells Scot mentioned.

We captured a higher oil price for our barrels in the DJ, which averaged $2.78 per of barrel off WTI. This was a 50% year-over-year improvement. We maintain a strategic advantage relative to our DJ Basin peers based on our ability to capitalize on not having any firm oil transportation commitments. We expect to see these tighter oil differentials for the foreseeable future and are locking these tighter differentials with our physical purchasers with no take-or-pay commitments. We are also benefiting from higher NGL prices, especially ethane and propane, and expect that we will see slightly higher NGL price realizations as a percent of WTI.

In Utah, we recently took advantage of improved market dynamics with lower -- due to lower supply of wax crude for the Salt Lake City refineries and renegotiated our UOP marketing contract. Beginning May 1, we have secured differentials under $2 per barrel. This compares to an average of $7.75 per barrel off WTI for our East Bluebell asset during 2016. This tighter differential will make our 9-well East Bluebell recompletion program even more economic.

LOE averaged $4.09 per Boe and was in line with expectations. It was a 37% year-over-year improvement. DJ Basin LOE averaged $3.47 per BOE or a 28% reduction compared to $4.80 this time last year. Our operation team continues to do a great job in reducing field level costs.

Now onto the balance sheet. Consistent with our strategy of executing on items within our control and maintaining balance sheet flexibility, last week we completed the issuance of $275 million of senior unsecured notes due 2025. The proceeds of this offering will be used, along with some of the cash on hand, to redeem the $315 million of existing notes that are due 2019. This will close by the end of May.

Since the second quarter of last year, we have reduced long-term debt by 16% and lowered our annual interest burden by $6.5 million. We continue to maintain a very manageable debt profile with our nearest maturity not until late 2022.

We also enjoy a strong cash and liquidity position. We had $266 million of cash on hand at quarter end, which was subsequently reduced by the $26 million in early April with our normally scheduled interest payments.

We are currently in the process of undergoing our semi-annual borrowing base review and expect that our current borrowing base of $300 million will remain unchanged. We expect to finalize this in the coming weeks. As a reminder, we are currently undrawn on our credit facility and do not expect to use it this year for ongoing operations.

We continue to be an active hedger and are looking for opportunities in the market to add further support for our capital program and protect future cash flow. For 2017, approximately 2/3 of our oil production is swapped at $58.50 WTI, and we have approximately 3,100 barrels of oil per day swapped at 2018 -- in 2018 at $54.50 per barrel. All of this weighted to the first half of the year. You can find a full summary of our updated hedge position in the press release or 10-Q.

Now an update to our guidance outlook. We expect second quarter production to be approximately 1.45 to 1.55 MMBoe, which is an uptick from our first quarter production, as the wells we placed on flowback during the first quarter continue to ramp up. We're also reiterating full -- full year guidance of 6 to 6.5 MMBoe, and we expect to achieve a very competitive growth rate of 30% to 50% in 2018 as we execute on this year's program.

CapEx for the second quarter are expected to be $65 million to $75 million, and our range of total CapEx for the year remains unchanged, $255 million to $285 million. The remainder of our cost guidance is -- remains unchanged and can be found in our press release.

With that, I think we are ready for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question from Welles Fitzpatrick with Johnson Rice.

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Welles W. Fitzpatrick, Johnson Rice & Company, L.L.C., Research Division - Associate Analyst [2]

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Great quarter and great acreage add there under the reservoir. Should we think about the 36% improvement from the higher loadings and the 10% improvement from the stage spacing as cumulative? And I'm sorry if you mentioned this, but are those uplifts relative to the 600,000 curve?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [3]

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The way we do these things, Welles, is we take a drilling spacing unit and we take a couple of the wells and we try something different on them, like the increased sand volumes or the tighter stage spacing. So it's relative to the other wells in the drilling spacing unit. Its where that calculation comes from, and that is cumulative over the 2-year production history that we have of those 2 -- well the increased sand volumes is on a 2-year comparison. The tighter stage spacing is just a 1-year cum. So you hope that, that would continue to hold through as you go through months 13 to 24, and then you would hope that there's an additional increase as we move the sand loading from the 1,250 pounds to the 1,500 pounds that you also get an uptick in production in cums as well.

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Welles W. Fitzpatrick, Johnson Rice & Company, L.L.C., Research Division - Associate Analyst [4]

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Okay, perfect. And on the 1,500-pound design and 100- to 140-foot stage spacing, I believe the $4.75 million accounted for the loadings but maybe not for the tighter stage spacing. Any thoughts on to where that might move? I know you're punching below that right now.

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [5]

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I think the $4.75 million kind of takes into account both as well as some service cost inflation. And so, kind of keep in mind that we budgeted that $4.75 million for the entire year in '17. And first quarter, we probably spent $4.25 million. And so that's the reason for the underspend. So I don't know if we're heavy on our capital or not. We're just going to see how the rest of the year goes and where those tweaks in the completion design go as well.

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Welles W. Fitzpatrick, Johnson Rice & Company, L.L.C., Research Division - Associate Analyst [6]

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Okay, perfect. And then just one last one for me. Just eyeballing the reservoir, it looks like that 2,900 acres is about all of it. One, is that right? And two, are there any more owners permitting requirements given where those wells will be located?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [7]

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Don't really think it's going to be a big permitting thing. They're federal minerals so you have to do a little bit of NEPA work, environmental assessment type of work. But the team, I think, believes that probably second quarter of '18 or so, that those wells will be popping into the drilling schedule.

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Operator [8]

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Our next question comes from Brian Corales with Howard Weil.

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Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [9]

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I have a couple of questions. One, maybe a follow-on to Welles' question. I see that it looks like 1,500 pounds per foot and tighter spacing is kind of the new norm. Are you all going to test even tighter spacing in bigger, complete more sand going forward? Or are you kind of happy with this plan you have?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [10]

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We could, Brian. We obviously are kind of watching what others are doing as well. But I know a current pad that's being completed right now is going to go 100-foot stage spacing. So that will be kind of testing one of the lower ends. And then I think we'll have to kind of look at some results of the 1,500 pounds and see if we need to go larger or not. There are some operators that are kind of doing some more. I think we can look at those results. So I think we'll kind of evolved throughout the year a little bit.

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Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [11]

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Okay. And then I see you're recompleting some wells in the Uinta. Is this more exploratory? Or do you all have kind of -- have you all done this in the past? And maybe give an idea of what the current well is producing and what it could become? I'm just trying to figure out, I guess. What are you targeting here?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [12]

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Sure, Brian. It's still within those Green River sections. If you remember, that's a 1,800, 2000-foot section of Green River. And so this is just adding uphole additional Green River pay. So very low risk. And it's just very well mapped out. So it's just kind of normal course of business. And with the differentials being lowered, it makes it economical and attractive and just kind of a good base production optimization, operational thing to go do.

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Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [13]

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Okay, I got you. So this is just more uphole. And so I'm assuming you're going to see how these 9 do, and you may add some to that going forward.

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [14]

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Sure. The team has an inventory of these types of opportunities. When you're completing that whole 2,000-foot section, sometimes you didn't go all the way to the very top of the section in some of the older completions. And so it's just adding a few more layers. So we're just adding. It's basically just kind of setting the plug, perforating, doing some stimulation work, pretty routine.

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Operator [15]

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Our next question comes from Jason Wangler with Wunderlich Securities.

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Jason A. Wangler, Wunderlich Securities Inc., Research Division - SVP and Equity Analyst [16]

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Was just curious as far as you look at the completion schedule, are you able to get those on a calendar, or do you have a dedicated frac crew as you just start to kind of ramp up? How much you guys are going to complete in the rest of the year? Just kind of how you see it from an availability standpoint?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [17]

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I don't think we have a dedicated frac fleet yet just with the activity in the first half of the year. We may get to that point in the second half of the year with the 2-rig program. But yes, everything is on a schedule, and we feel definitely that we'll be able to meet the timelines that we're laying out here and execute according to the plan, our internal plan, the guidance that we're delivering. So it's all scheduled and should be executed timely.

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Jason A. Wangler, Wunderlich Securities Inc., Research Division - SVP and Equity Analyst [18]

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Okay. And maybe just similar but on the drilling side. You continue to drive down the drilling days, I guess, just under a week now. I mean that puts you in a very good spot as far as getting your 70- to 75-well program done this year. Is there a kind of a time that you're looking at that second rig? Or does that even kind of move around given the fact that you keep increasing that you can kind of almost push that further back given how well you're doing with the 1 rig now?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [19]

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Yes. It kind of moves around a little bit. I think, as we continue to drill faster, the need to add that second rig early in second quarter kind of slid to say maybe we'll do it in the second half of the second quarter. And so that's kind of why you saw maybe a 30-day delay. But clearly, there's rig availability, and so that's not an issue. And obviously, we have the permits and all the necessary documentation to get started. So you'll see us here in the next 30 to 45 days probably start.

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Operator [20]

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Our next question is from Gabe Daoud with JPMorgan.

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Gabriel J. Daoud, JP Morgan Chase & Co, Research Division - Senior Analyst [21]

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Maybe just following up on previous question on the second rig. Just trying to think about how you sensitize that based on oil prices. If we stay around here, the low $50s or high $40s, or if you take another lag load does that impact at all how you think about running the 2 rigs?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [22]

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Sure. I think, we always look at changes in the commodity price. With our entire acreage position basically being HBP-ed and without any marketing commitments or other type of obligations, we can change and make decisions based on commodity prices, the ability to hedge, so all of those things factor in. But if you look at those economics tables, if you look at something in the low $50s, we're generating a 45-plus percent rate of return, probably feel pretty comfortable going forward. Obviously, we would look at things differently, if things go back -- if oil prices long-term go back into something in the $40s.

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Gabriel J. Daoud, JP Morgan Chase & Co, Research Division - Senior Analyst [23]

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That's helpful. And then just one quick follow-up on the Uinta renegotiating the marketing contract. Does that impact at all how you guys think about the asset within the portfolio? I guess what I'm asking is, now that realizations are improving, do you try to put it on the block again, I guess?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [24]

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I think it definitely makes it more profitable. It improves the cash flow. And so you're probably right. You would think it would enhance the value if we chose to monetize it at some point. And I still think, that we probably will look to monetize it at some point. But no immediate plans today to do that.

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Operator [25]

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Our next question is from Derrick Whitfield from Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst [26]

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Regarding the tighter spacing and higher profit density that you referenced earlier in the call, how do you guys think that's going to change the shape of the production profile? Will it take longer to reach peak with that optimal completion?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [27]

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Shouldn't take longer to reach peak. What you hope is that the peak is actually higher and perhaps the decline is shallower. And we've seen that on those couple of data set points that I referred to earlier where we have the 2 years of production history, and so that would be kind of the expectation.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst [28]

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Fantastic. And then just building on the question that Welles asked earlier, is it fair to assume that average field EUR should be 10% or higher than the 835 that you guys mentioned in your Howard Weil presentation?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [29]

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I'm not following the 835, I guess.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst [30]

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Yes. I'm just looking at the average EUR that you guys have mentioned in your presentations. The one that I'm looking for XRL reference is third-generation at 835,000 barrels equivalent. And my comment was, given the changes that you guys have made really sense walking that design up, would it be safe to assume that EURs would be minimum to kind of 10% higher than that? Or has that already all been baked into the 835 number?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [31]

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Yes. I'm still not following the 839 number. I think the Howard Weil presentation, we have some illustrative economics of a 500 curve, a 600 curve or a 700 curve that's in there. And yes, the expectation is that we would build from those field averages as we continue to improve on our completion techniques.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD and Senior Analyst [32]

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Okay. And then just last question if I could. If you could share with us the house view on Anadarko's vertical announcement from last week and expected impacts to you?

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [33]

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Obviously, that was an unfortunate tragedy. And obviously, our company, is an active member of that community, our thoughts and prayers go out to that family and that entire community on this incident. In terms of impact to our company, it's really pretty small considering the rural nature of our properties. If you look, our properties sit to the northeast side of the field. We're in a very rural area, just to kind of give you some comparisons. As this incident was unfolding last week, there were some -- we went out and tested all the wells that we had that were less than 250 feet from an occupied structure, and there's only four of those. We also went out and looked at the wells that we have within 500 feet, and there's 11 wells. And so we really don't sit in a municipality or in a rural environment, and obviously we want to be compliant with all of our testing, and the COGCC put out some new guidelines last night that obviously we will execute on. But the overall impact to our base operations should be pretty small.

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Operator [34]

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Our next question comes from David Beard with Coker & Palmer.

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David Earl Beard, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst - Exploration and Production [35]

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A couple of bigger picture questions on the balance sheet and on sand. First, on sand loadings, just wanted to get a little more color on the impact of increased cost of sand for your wells.

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R. Scot Woodall, Bill Barrett Corporation - CEO, President and Director [36]

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The way that we're kind of looking at it is, the change from, say, maybe 1,000 pounds to 1,500 pounds is probably $0.25 million, and probably the incremental costs associated with going from 170 feet to 100 feet may be like other $0.25 million. So it could that you're adding about $0.5 million roughly in well cost associated with those 2 enhanced completion techniques that we're executing on.

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David Earl Beard, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst - Exploration and Production [37]

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Okay, that's helpful. And then just the bigger picture question relative to oil and outspend and cash and your revolver. I know you mentioned you wouldn't expect to use the revolver. But there is a level of just cash on the balance sheet you wouldn't want to drop below before you would match spending with cash flow?

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William M. Crawford, Bill Barrett Corporation - SVP of Treasury & Finance [38]

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Dave, it's Bill Crawford. We look at it at the opportunities we have in front of us. And with the economics that Scot talked about, 45% plus rate of return, we feel it's helpful to put the cash on hand to deploy it to the levels that we can. And obviously don't want to draw on the revolver more than probably about 25% to 50% of usage. So as we look at our outlook, that's we put all that into play.

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Operator [39]

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I'm showing no further questions at this time. I would like to turn the call back over to Larry Busnardo for closing remarks.

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Larry Busnardo, [40]

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Great. Again, thanks everyone for joining us today. Feel free to contact us if you have any additional questions, and we look forward to seeing you at future investor events. Thank you.

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Operator [41]

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Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program, and you may now disconnect. Everyone, have a great day.