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Bill Barrett (NYSE:BBG)

Q4 2013 Earnings Call

February 21, 2014 11:00 am ET

Executives

Jennifer C. Martin - Vice President of Investor Relations

R. Scot Woodall - Chief Executive Officer, President and Chief Operating Officer

Robert W. Howard - Chief Financial Officer and Treasurer

Analysts

Andrew Venker - Morgan Stanley, Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation Fourth Quarter and Full Year 2013 Earnings Conference Call. My name is Denise, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jennifer Martin, Vice President of Investor Relations. Please proceed.

Jennifer C. Martin

Thank you, Denise. Good morning, everyone. Thank you for joining us. Speaking today will be Chief Executive Officer, Scot Woodall; and Chief Financial Officer, Bob Howard.

Just a few quick notes before we get started. Our annual report on Form K was filed yesterday afternoon and is available on our website under SEC filings.

Second, as usual, I need to remind everyone of the forward-looking and other cautionary statements provided in yesterday's earnings release.

In addition, during our discussion today, we will make reference to non-GAAP measures, such as discretionary cash flow, adjusted net income and finding and development costs. Reconciliations to the appropriate GAAP measures may be found in the earnings release posted on the homepage.

Lastly, we will post an investor presentation prior to our participation in the upcoming Simmons and Howard Weil conferences, with dates and times provided in yesterday's release. We hope to see many of you at these events.

And with that, I will turn it over to Scot to get started.

R. Scot Woodall

Good morning, and thank you, all, for joining us. Throughout 2013, we outlined several key objectives for the company, all designed to increase value to our shareholders.

Let's recap what we achieved in 2013. First, we focused our investments in 3 key oil programs, each of which demonstrates significant growth in reserves and production.

Let's start first with oil growth. Our oil production was up 30% for the company. In the DJ Basin, we drilled 61 wells and doubled our total production in -- over the period. In the Uinta Oil Program, we drilled 57 wells and increased production by 38%. In the Powder River Deep Oil Program, we also doubled our production.

Moving to proved oil reserves. As a company, we were up 65%. Our oil program drilling locations are up nearly 2,000 growth locations or 68%, and that translated to a reported F&D cost for 2013 of $8.30 a barrel.

In the DJ Basin, we increased total proved reserves 355% and added 615 gross drilling locations.

In the Uinta Oil Program, we increased total proved reserves 11% and successfully completed two 80-acre pilots in the Blacktail Ridge area.

In the Powder River basin, we increased proved reserves by 1.8 million barrels with a nominal 5-well operated drilling program.

In terms of both production and reserves, we ended the year with commodity balance. We are approximately a 40% oil, 20% NGL and 40% natural gas company.

Second, we delineated 70% of our acreage position in the Northeast Wattenberg. I would first say that we were pleased with our tremendous reserve and production growth in this area. Our 2013 program was a delineation program designed to gather data about our acreage and to test horizontally 3 different horizons.

Additionally, we tested a number of drilling completion and production techniques. I think the key takeaway is that the 2013 delineation program provide the information and data to us to give the company confidence in our ability to profitably grow this asset in the future.

Third, we are driving profitability as demonstrated by improved margins. Our pre-hedged per unit operating margin was up 28% 2013 over 2012. We demonstrated capital discipline by lowering capital guidance during the year and meeting that capital guidance. Both the DJ Basin and the Uinta Oil Basin reduced drilling and completion costs in 2013.

Next, through portfolio management, we lowered our long-term debt down by about $189 million 2013 over 2012 levels. These items drove our success, drove value and resulted in returning a 50% increase in our share price to our shareholders. Our success also increased the present value of the company by 24%.

We're very pleased by our 2013 accomplishments, which now positions the company well for 2014.

So let's discuss our objectives for 2014. We plan to continue to drive operating margins by allocating our capital to the highest rate of return areas in the portfolio. We expect our capital program to deliver an internal rate of return of approximately 40%. We will remain focused on our key oil plays and expect to deliver at least a 30% growth in oil production.

As we have done in 2012 and in 2013, we will continue to evaluate our portfolio for opportunities that create the most value for our shareholders.

I'd like to discuss briefly our key oil programs. We'll start with the DJ. In 2014, we will spend about 75% of our capital budget, around $400 million, running a 3 to 4-rig program to spud approximately 85 gross, 60 net operated wells and participate in another 45 or so gross wells and approximately 10 net wells.

Our drilling focus will be in the Northeast Wattenberg 40,000-acre position, yet we will also expand our drilling to include our 14,000 net acres in the core Wattenberg area and roughly, the 20,000 acres in the Chalk Bluffs area.

We will test increased density this year by drilling 2 sections with 20 wells per section each. Our review of offset long laterals drilled in our area indicates superior economic returns. Our acreage position lends itself well to long laterals and our plan includes a number of 9,000-foot laterals.

We are clearly very pleased with the production reserve growth in the DJ in 2013 and have designed a program for 2014 that will capture value for our shareholders.

Moving on to the Uinta oil play. In 2014, we will spend approximately 15% to 20% of our capital budget or about $90 million running a 1 to 2-rig program to drill about 35 gross, 22 net operated wells.

The 2014 drilling will be focused in the East Bluebell area, which offers the highest returns in the area, plus an 8- to 10-well drilling obligations in the Blacktail Ridge-Lake Canyon area.

Lastly, in the Powder River Basin, we expect to allocate approximately 5% to 10% of our capital in 2014. Our focus in 2014 will be initially on evaluating our acreage position and attempting to solidify that position.

So to kind of wrap things up here a little bit, I would say our team demonstrated excellent execution on our plan in 2013, and we have set the foundation for another solid year in 2014.

I will now turn the call over to Bob.

Robert W. Howard

Okay. Thank you, Scot, and good morning, everyone. I will reiterate that 2013 was a good year for the company and for our shareholders. We'll review some of the highlights from the year, specifically from the fourth quarter.

I'd like to remind you of the schedules in our earnings release from yesterday and in the Form 10-K for additional details about our business.

We are now reporting our production in barrels of oil equivalent rather than Mcfe, and for the full year, 3-stream production totaled 14.5 million BOEs, meeting the high end of our guidance range. Oil production for the year increased by 30%, driven by production growth of more than 100% in the DJ Basin along with 38% production growth in the Uinta Basin.

Fourth quarter production was 3.3 million barrels of oil equivalent, reflecting tremendous growth in the DJ Basin. DJ production doubled from the fourth quarter of 2012. It was up 55% from the third quarter, reflecting our back-end loaded 2013 drilling program.

Fourth quarter oil production was impacted by a sequential decline in production from the Uinta Oil Program as we stopped drilling in that area in the third quarter of 2013.

Fourth quarter natural gas production reflected the sale of our West Tavaputs dry gas field that closed on December 10.

Fourth quarter NGL volumes of 6,200 barrels per day reflected higher processing plant recovery rates than the third quarter. Those rates are under the control of the plant operator.

Adjusted for asset sales, our year-end exit rate production was oil of 10,900 barrels per day, natural gas of 71 million cubic feet per day and NGL supply of 5,100 barrels of oil per day or barrels per day. Approximately 6% of oil and NGL is achieving our commodity balance.

During the quarter, we closed the sale of the West Tavaputs gas field for $369 million, which includes the purchaser assuming $46 million of the lease financing liabilities.

The cash proceeds from the sale were applied to reduce our revolving credit facility. Our year-end debt was reduced by $189 million from the end of 2012. And our debt-to-EBITDAX ratio at the end of the year was at 2.7x.

In the fourth quarter, discretionary cash flow was $1.62 per share and adjusted earnings were $0.11 per share, both of which are well ahead of Street consensus. And for the full year, discretionary cash flow was $281 million or $5.92 per share and adjusted net income was a loss of $20.5 million or $0.43 per share.

And I'd like to cover a few items related to the guidance that we provided in our February 4 release. Capital guidance for the year is $500 million to $550 million and assumes an average of 3 to 4 rigs in the DJ Basin and 1 to 2 rigs in the Uinta Basin, reflects drilling approximately 200 gross and 100 net development wells, and including participation approximately 85 gross net non-operated wells.

Approximately 75% of our capital expenditures will be allocated to the DJ Basin.

Production guidance for 2014 is 11 million barrels to 12.2 million barrels of oil equivalent and is expected to include at least 30% growth in oil production.

Oil production growth in 2014 will be generated from our DJ Basin Program as reduced expenditures and drilling in the Uinta and the Powder River Basin should result in year-over-year production declines from most of those areas.

A couple of points to better align your models with our internal plan and guidance. Our guidance reflects oil production growth as weighted to the second half of 2014. For the first half of 2014, our internal plan assumes oil production will be generally flat to up slightly from the fourth quarter of 2013.

In regard to our natural gas liquids, as reflected in our fourth quarter numbers, we expect that our NGL sales revenues, net of transportation and processing fees, will be approximately 60% to 70% of blended mobility prices due to our marketing agreements and percentage of proceeds contracts.

NGL volumes depend on processing plant recovery rates that are difficult to project. I'd assume that the NGL exit rate of 5,100 barrels per day is a better starting point for our 2014 estimates than the average fourth quarter volumes.

Our balance sheet is in good shape. We're well hedged to support our cash flows. For 2014, we have approximately 3.2 million barrels of oil hedged at approximately $94 per barrel and 21.3 Bcf of natural gas hedged at a Rockies price of approximately $4.20 per Mcf.

Our capital expenditure program is expected to be roughly a couple hundred million dollars more than our cash flow for the year. That financing need will be funded through -- with our revolving credit facility that had $484 million in available borrowing capacity as of the end of 2013.

That being said, we'll continue to actively manage our asset portfolio to maximize the values of our properties.

With that, that concludes our prepared remarks. And I'll turn it over for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Drew Venker with Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

I was hoping you could talk through activity levels in your different Niobrara areas, maybe in terms of how many wells you plan to drill in each area this year.

R. Scot Woodall

It is a -- Drew, we are -- obviously, our drill schedules continue to move around somewhat, but the majority of them is going to be in the Northeast Wattenberg. We will drill some in the core and just a very small number up in Chalk Bluffs.

Andrew Venker - Morgan Stanley, Research Division

Okay. So, Scot, maybe less than 5 in Chalk Bluffs. And the core, can you give us a better sense? Is that maybe 10 wells or so?

R. Scot Woodall

The 5 or less in Chalk Bluffs is probably right. It's probably a little bit more in the core.

Andrew Venker - Morgan Stanley, Research Division

Okay. Maybe can you give me some more color around your well results in Wattenberg in the fourth quarter, just between how the performance looks between the different zones you tested, Niobrara C and D -- I'm sorry, B and C. And Codell anything, any color there as to how the different zones looked.

R. Scot Woodall

Sure. Most of the focus in the fourth quarter was still on the Niobrara B and most of it was all in the Northeast Wattenberg area. So there's a -- I think the C well are 2 that we -- there's only a well or 2 that was drilled in Q4. So most of the activity in Q4 was related to the B. Expanding on that, I guess, a little bit, as you kind of break that into the various areas, the activity that we've had in the southern acreage really has been great, and it continues to meet our expectations and we've been very pleased with those results to date. The north area of the Northeast Wattenberg is probably where we've seen more variability. And that was probably ticked up a little bit on our last release with some of the variability of some of those well results. It's been kind of interesting, the 30-day IPs of some of those wells have probably been somewhat below our expectations. We're now, as you look at the 60-day rates on some of those wells, and on a few examples, the 60-day rate is actually higher than the 30-day rate. So clearly, we've got some variability going on there. We're seeing some variabilities in GOR, which is translating into energy. And so I think that's why you're seeing the 60-day rates hold up stronger than the 30-day rates, but the actual 30-day rate IPs are maybe somewhat lower. So how all of that translates into EUR I guess is something that we're going to be watching over the next several months. But I guess, I kind of do want to go ahead and make the point that when we think about all of the results that we've gotten to date in 2013, I don't think any of it has led us to believe that we've condemned any of our acreage. I think we've seen variability across our acreage, but we still do believe that all of acreage is prospective. And I probably would elaborate a little bit more. You may be getting more of an answer that what you've bargained for, Drew, in the first question here. But I guess I also would elaborate a little bit. To see some variability in the results does not surprise me at all. When you think about what all we attempted to do in '13 by testing kind of all parts of the acreage, testing 3 different horizons and testing a variety of completion and drilling techniques as well as a variety of artificial lift techniques, I think you are going to see some variability in there. I think the key takeaway that I hope the investment community would grasp upon is that obviously, we're extremely encouraged by the results as indicated by us putting 75% of our capital in '14 into the play. And so obviously, our team is still very excited about the play and believe that we're going to deliver very solid economic results going forward.

Andrew Venker - Morgan Stanley, Research Division

That's helpful, Scot. I guess going back to the southern portion of the Niobrara acreage that you mentioned. How much of that acreage do you expect to be delineated this year? I mean, is that essentially going to be 100% delineated by the end of the year? And would you just remind us why you think the southern portion of that acreage is actually some of the best that you have?

R. Scot Woodall

Sure. And to date, we have probably only delineated maybe half of that southern acreage in 2013. In '14, as I look at the drill schedules, I'm not going sure we're going to touch all the corners of it in '14. And really, that's being driven by infrastructure. All the infrastructure is coming from the north, and so we're doing a very logical step down to the south. So I'm not sure if we're going to get all of it delineated in 2014. But the reservoir characteristics down there look great. Actually, as you go to the south, the Niobrara C becomes as thick, if not thicker, than the Niobrara B. And so we really think that we've got 2 targets there, and we've tested both of those targets in our '13 drilling program and, as I indicated, with very positive results to date. So we're pretty excited about the south. It seems like it's been more consistent in terms of results than the north in the limited amount of data that we have to date.

Andrew Venker - Morgan Stanley, Research Division

That's helpful, Scot. The last one for me was if you could provide any color or recent developments, current and recent developments in the Colorado fracking dam proposals.

R. Scot Woodall

Sure. I'd just kind of recap, and I think everybody knows there were some ballot initiatives in November that some local municipalities tried to regulate the oil and gas industry. Those all passed. They were largely symbolic in the fact that there was not a tremendous amount of oil and gas activities in those particular municipalities. But I think the concern is as that expand into other municipalities really is probably the challenge of who has primacy over regulating the oil and gas industry, whether that's the state or the local municipalities. There's several lawsuits, including one by the Attorney General of the State of Colorado, against those municipalities, saying that it is a state primacy issue, not a local issue. Whether or not it makes its way onto the ballot in this coming November election, I think, is the real issue. And I think there's going to be a tremendous amount of noise over the next several months associated with that issue. The recent polling results in the state would say that it does not have a majority of the support of the citizens of our state, but I'd say, I think it will be something that is going to be noisy for the next several months. The way a couple of the preliminary legislation is being written that sits out in committees right now is attempting to not only put local municipality control over the oil and gas industry but really over all industry. And so when you think about how that is being written, it may actually provide a little bit more of a rallying point for all of the businesses in Colorado to think about whether or not they want to do business in Colorado if they have an uncertain future with the municipalities taking control. That all being said, I really think that the issue, as I said, is going to be noisy, but I really don't think it's going to be something that it will gain support and actually pass and limit our ability to be able to exploit this asset going forward.

Operator

Our next question comes from Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

A quick one on the lifting techniques and completion designs. I know you guys were testing a variety of those. Do you have any broad learnings you see from that work or does it just kind of vary by area as to what's best practice?

R. Scot Woodall

I guess, probably the largest takeaway was probably the first half of the year we were using a smaller stimulation design and at the second half of the year we used a larger stimulation design. I think that has been probably the most improved. The second thing probably goes into the artificial lift. Most of our acreage position had little infrastructure on it. And so you are forced to use artificial methods that included plunger lift, pumping units, actually, even submersible pumps versus gas lift. And we really believe that gas lift has been the better technique going forward. And I think we are now getting in a better position where we have more infrastructure built out, that more of our wells can go immediately on gas lift. So I think kind of a combination of larger stimulations and putting the wells immediately on gas lift has improved our results through time. And I would expect for it to continue to improve our results through time.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Very good. And then with the Wattenberg interior, I believe you guys were testing a multiple well pad there. Can you just remind us on the configuration and any update you have on that pad in the Wattenberg interior?

R. Scot Woodall

Sure, that is a pad that it will eventually be 20 wells in a section. We drilled 10 wells towards the end of last year, and we're in the completion stages of those first 10. And we'll be drilling the remainder 10 as well. So it's one of the 20-well pad. And on that 20-well pad, it's configuration is 8 Bs, 8 Cs and 4 Codells.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Great. That's very helpful there. And then one last one for me. Can you just remind us on your plans for testing Chalk Bluffs this year and then any industry activity around that Chalk Bluffs asset?

R. Scot Woodall

Sure. The Chalk Bluffs, we will do just a few wells, and we're going to target the Codell in the 2013 program -- excuse me, the 2014 program. I got to get in right year here, I guess. But we'll test a few Codell wells up there. The industry has drilled a few wells, a few Codell wells up there that looked very interesting. The Codell looks very prospective across our acreage. We have kind of reinterpreted our seismic from when we were up there drilling a couple of years ago and just think it deserves additional testing. We have more than 20,000 acres up there, and it just seems like it's the right thing to do to kind of test it a little bit. But there's been a number of operators testing both 4,000-foot laterals and 9,000-foot laterals in the Codell in pretty close proximity to us.

Operator

Our next question comes from Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

I'm curious, you talked about the 30-day rates on a couple of questions ago, and you were seeing the 60-day rates. When you guys gave those 30-day rates, are those -- can you maybe just give us a little detail? I mean, are those spaced at the first 30 days of production? Are you synthesizing those depending on when you're putting on a lift or anything like that? Just trying to get an apples-to-apples comparison between your numbers and maybe some of the others' in the industry.

R. Scot Woodall

Sure. Ours is the first 30 days of production. If the well went down for a day or 2 while we installed our artificial lift, we would extend that, so maybe that's the first 32 days or something, if you know what I'm trying to say there. So it's the actual first 30 days that it flows for most of the day.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. And I mean, is there -- maybe I mean, give or take, might be an average. But on those wells, because you're saying now you've kind of been able to put gas lift on immediately, which looks like it really does help the wells out a lot from what I've seen. I mean, is there a relative timeframe because, obviously with the 60-day rates looking even better, I think that the gas lift is obviously working. Is it 15 days in, 20 days in, give or take? Is there something there?

R. Scot Woodall

I don't think it's that exact of a science. I mean, I think we are drilling the wells out, drilling out the plugs really within a day or 2 of finishing the stimulation, installing the gas lift systems. And then I think as the well dictates, you start injecting gas. And I think that kind of varies a little bit from well to well.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay, that's helpful. And then just one other one. I know that you guys kind of are probably looking to put out type curves and things later, but is there any way to get an estimate from what the leasing engineers put on your Niobrara wells? I mean, I guess I can try and back-of-the-envelope calculate it, but I was wondering if you have an idea of what they were giving you credit for because obviously the reserve growth was huge.

R. Scot Woodall

Sure, we can discuss that a little bit as well. There's a range, obviously, in the reserves that we booked at year end. And so that range is in the approximate range of about 250,000 BOE to about 350,000 BOE in terms of reserves per well. I'll say a couple of things and to put a little more color on that. If you think about the way that the reserve booking process goes is you've got to have sufficient amount of production by the time your reserve auditor is looking at that data, which in our case that is around the November timeframe. And so if you back up, and you want 60 or 90 days of production, you're back to wells that were really drilled between January and say, July, in my example here. And so those are the wells that we actually booked proved reserves associated with those. And so that is why I think you see that range of, say, 250,000 to 350,000 because most of those wells that we're discussing that we booked reserves on in 2013 were the wells that were stimulated with the smaller frac treatments as well as had some of the early designs of artificial lift associated with them. The other comment that I guess I'd make is we do see some variations across the acreage at least from the amount of data that we had to book reserves on. So when you're still very early in the cycle and you've got 60 days of production and you're hanging some sort of type curve on there, it kind of leads to those variations of 250,000 to 350,000 barrels of oil equivalent. I think as we get more production history, hopefully, we'll see that range tighten and we'll be able to predict that a little bit further or see if each area has its own unique type curve or if one type curve fits across a larger piece of the acreage.

Operator

Our next question comes from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

A couple of questions, Scot. You talked about the northern acreage, I guess, being more variable. Can you -- is it more variable with the gas percentage or oil percentage or is it just flow rates? Can you maybe elaborate on that a little bit?

R. Scot Woodall

Sure, Brian. What we have seen is we have seen even on the same pad some variability in the 30-day IP rates. We have seen some of those 30-day IP rates that are lower than probably our expectation, but that is that area that as I spoke to earlier where we've seen the 60-day IP rates are probably higher than our expectations. We've seen lower GOR, which obviously is translating into lower energy, so that's got to be impacting that initial flow rates I think a little bit. So what that does in 60 days and 90 days, I think we're going to have to see. So obviously, with the lower GORs, that is translating into a higher oil cut. So where all this bounces out between lower GORs, higher oil cut, lower 30-day IP rates, perhaps higher 60-day IP rates is where we're still kind of early in the data gathering to be able to hang our hat on. This is the EUR for that particular area, or here is the optimum development for that particular area. But it is acting, like I say, a little differently than what we've seen in other parts of our acreage.

Brian M. Corales - Howard Weil Incorporated, Research Division

How much of that acreage that you're seeing this -- of the 40,000 acres, how much of that is kind of more oily but, I guess, lower pressures and whatnot?

R. Scot Woodall

That's a kind of a hard one to answer, Brian, but in a...

Brian M. Corales - Howard Weil Incorporated, Research Division

You can ballpark me.

R. Scot Woodall

We're still early. We've drilled maybe 10 wells to a dozen wells or so up in that northern area. And that northern area is 15,000, 17,000 acres in total. We've seen it in parts of the wells that we've drilled to date. So I know that's kind of vague, but I guess, we're still kind of vague in the data collection part of that process. I still think the big thing is when you think about this -- and we talked about 30-day IPs and how that translates into EURs and ultimately, we're trying to get how that translates into internal rate of returns. As I kind of said earlier, we haven't seen anything that says that our rate of return is 0 and that we have an uneconomic well. I don't think we've got anything that would say that we've got uneconomic wells or we've got acreage that we're ready to lob off of our totals and say that it's not prospective. So I think that's really the takeaway that I'm trying to deliver somewhat today, is it looks like we do have some variability, we may have some variability in our oil cuts and our GOR, and how that translates into ultimate recoveries, that's all still be worked out. But we're still excited that we've got a development plan that we think will generate very positive rate of returns.

Brian M. Corales - Howard Weil Incorporated, Research Division

And Scot, can you mention what you're currently producing? Because I think in the fourth quarter, you put a lot of Niobrara wells online. Some of them may have been kind of back-quarter loaded, which I would think would impact 1Q. Can you maybe talk towards that? And just on -- and I know Bob talked about kind of the production kind of through the year, which I would have thought we'd see kind of a bigger jump in 1Q. Is my assumption wrong?

R. Scot Woodall

Yes. Jennifer has been shaking her head at me, that I can't talk probably too much. You just have to remember, in the company's portfolio, you have to remember you've got a lot going on. And so you can think about the DJ wells and activity and what we're doing. You think about the multi-well pads because most of our development in DJ is going to be multi-well pads. That creates some noise in some of the data. You have to also think that you've got declines going on in the Uinta play because we haven't drilled out there in about 6 months. You took a step down in the Piceance for another 3% with the transaction that we'd done back in 2012, and you've got Piceance on decline too. So you've got a lot of noise in the numbers a little bit. I think Bob was just trying to explain kind of how we are modeling it internally and trying to get you guys kind of think about it in terms of those realms of production by quarter. But I would say, I'd reiterate it again, we took all of that into account when we issued our guidance here just a few short weeks ago.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then one final one, and then I'll hop off. The Uinta, I know it's in decline. You haven't been active there. But you're all going to put -- when are the rigs coming back and when do you think that decline can be stemmed?

R. Scot Woodall

The rigs are back out there as we speak, so they did -- they have started. But obviously, that production doesn't come on until later.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I just want to follow up a little bit on the guidance, sort of the production trajectory a bit. What are the key milestones on both the midstream and the upstream that you're watching for to have confidence that you'll achieve that or above the midpoint of guidance? Are there other certain things -- I assume, particularly, in the DJ that you and we should be following?

R. Scot Woodall

I don't know if there's any particular milestones. I think it's about our execution, and I think we're on track to execute.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. There are specific -- I guess, are there specific pipelines or specific midstream bottlenecks that could get in the way at all? Or is it solely really in your control in the upstream side to get your pads online on time and then to have the well performance be what you think?

R. Scot Woodall

Obviously, we have to work with our partners on the midstream to make sure that the midstream resources are there timely. But we're working very closely with them, and right now we don't see any obstacles to that.

Brian Singer - Goldman Sachs Group Inc., Research Division

And you made a point on variability in the GORs I think as it was related to some of your northern area wells. Was that based on 2 wells that were drilled one next to each other having different mixes? Or the wells as they progressed through their lives seeing much different GORs? What are your expectations over the life of your DJ wells regarding GORs?

R. Scot Woodall

It's kind of twofold. One, I would say that the variability that I was speaking to is between wells, so it's been one well and another well where we've seen some variability in flow rates and GORs. If you look at GOR through time, which there again we have all of like maybe a year of data, I think our expectation in looking at the curves of others in the field is that GOR increases through time a little bit. But we don't have a sufficient data on our acreage to draw all those conclusions.

Operator

Our next question comes from David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Can you talk about the 9,000-foot laterals? Where are you drilling those? And is that based on acreage -- contiguous acreage? Or is that based more on geology? Or can you just give me a little color there?

R. Scot Woodall

Probably both. Those tests will all happen in that Northeast Wattenberg position. So the drilling that we'll do in the core part of Wattenberg will all be the regular 4,000-foot laterals. The blockingness of the acreage position in the Northeast Wattenberg area really lends itself to drilling longer laterals. And if you look close to our acreage within a couple of miles of our acreage, there has been, I think, up to 9 extended reach laterals drilled in very close proximity to our acreage. And when we review those results, they're very encouraging, and it looks like that they deliver a superior economic return. And so transferring the information from those locations on to our acreage position seems like it's the right thing to do.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. That makes sense. Can you give us a little bit of color about Chalk Bluffs? Can you kind of give us a little more detail about what you're chasing or what -- yes, I guess just more on what you're targeting to kind of -- maybe what your goal is up there?

R. Scot Woodall

Sure. This year's program is really focused on the Codell. We definitely think there's some prospectivity of the Niobrara B up there as well. And if you remember early in our development in DJ, we drilled a few Niobrara Bs up there with a little bit of a mixed results. I think you've got a little more variability going the geology, a little bit more fracking, I mean, a little bit more fracturing going on up there. And so when now we have seismic and we've been able to calibrate that seismic with some of our early well results. And so we just think that it's got some prospectiveness that we need to go and test. And so like I say this year, we'll just be a few wells in the Codell.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Then, is it fair to say that industry activity has picked up in the area?

R. Scot Woodall

It has. And you've seen quite -- I can't say quite a few, but you've seen a few Codell tests in the area that looked very encouraging, both short and long laterals.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And then final question, differentials. I know out years -- in 2015, everything looks fine. Can you just talk about right now what you guys are expecting as far as diffs go over the next 3 or 4 quarters?

R. Scot Woodall

Sure. Our fourth quarter '13, our differentials stayed in that $9 or $10 range, and that's kind of where we were for most of 2013. We do expect those to -- in the first half of '14, to maybe be up a couple of dollars, and that's the way we're modeling it. And then we'll see kind of what happens after the first 5 or 6 months of '14.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. I'm just looking down my list. I do have one more. When you say 70% of your acreage is delineated, and I think in the presentation you said something about reserves or you did in the press release. But how do you -- what does that mean for us? How do you decide if some is delineated or not? What's the logic behind that? How do you guys look at that?

R. Scot Woodall

Sure. I guess the way that we got there is that our third-party reserve auditor gave us proved reserves associated with 70% of the acreage, so that is some amount of proved reserves. Can I say that that's the ultimate spacing or the ultimate recovery that we think we'll get from those wells at acreage? Probably the answer is no, but that over 70% of the acreage in the Northeast Wattenberg, we booked some amount of proved reserves.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And then the 30%, those would be PV10 positive, right?

R. Scot Woodall

Correct.

Operator

[Operator Instructions] Our next question comes from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Another question on the guidance trajectory there. Just for our models here in terms of calibrating it, what's a good base decline rate we should put on the Uinta? And if you've got kind of a company-wide decline rate on PDPs, that would be helpful too.

R. Scot Woodall

Probably, UOP is something in that 10% to 15% type of decline year-over-year. I probably don't have a total company PDP. The other big driver of that is the Piceance, which is probably something that sits closer to 20.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay, appreciate that. And then just a question on the variability you're speaking to, Scot. Is this something you ultimately can't control and really plan for through either seismic or just well control and logs? And just how far along really are you in kind of making that determination across your acreage?

R. Scot Woodall

The anticipation is, the answer to your question is absolutely yes. That's what hopefully we're employing very smart technical people to do is to be able to take the well information, take the logs, take the seismic and be able to accurately predict the performance of every single acre that we own. So that is our ultimate goal. It obviously comes with more production history on what we've drilled to date and perhaps additional delineation tests.

Michael Kelly - Global Hunter Securities, LLC, Research Division

And in terms of just timing of that, I know this is a process, probably. I don't know if this is something that takes up most of 2014, at the end of it you could say, okay, we've got 80% or 90% of the Niobrara delineated? Or is there any milestones that in your eyes when you really kind of have this acreage kind of mapped out and truly know what you have?

R. Scot Woodall

It's really more of a continuous process is probably the way I would like to state it versus setting an expectation of a milestone. It's my challenge, I think, to all the technical people that work at this company that we're always trying to continuously improve, whether that's improving the results or improving the predictability of results. And so I think it's more of a process.

Operator

We have a follow-up with Jason Wangler.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just 2 quick ones. I'm just doing some math on the reserves. Do you have, by chance, at West Tavaputs what the proved development break down was versus just the total reserve there when you sold it?

R. Scot Woodall

We probably do. It may be something that we need to have Jennifer call you back offline with, if that's okay, Jason.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Yes, that would be fine. And then the last one, I'd be remiss if nobody asked on. In the Uinta with the pricing and infrastructure, are you guys seeing any more movement on whether it's rail or just with the refineries adding their capacity, how you're seeing pricing now and maybe even going forward for the year?

R. Scot Woodall

Yes, we're still modeling at the same differentials that we saw in '13.

Operator

We have no further questions. I would now like to turn the call back over to management for closing remarks. Please proceed.

Jennifer C. Martin

I just want to say thank you to everyone for joining us today, and always feel free to give me a call with any follow-up questions.

Operator

This concludes today's conference. You may now disconnect. Have a great day.

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