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Executives

Jennifer C. Martin - Vice President of Investor Relations

Fredrick J. Barrett - Co-Founder, Chairman, Chief Executive Officer and President

Robert W. Howard - Chief Financial Officer and Treasurer

R. Scot Woodall - Chief Operating Officer

Analysts

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

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Jeffrey W. Robertson - Barclays Capital, Research Division

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

Dan McSpirit - BMO Capital Markets U.S.

Dan McSpirit - BMO Capital Markets Canada

Michael Kelly - Global Hunter Securities, LLC, Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Joseph Patrick Magner - Macquarie Research

David Magruder - Knighthead Capital Management, LLC

Bill Barrett (BBG) Q3 2012 Earnings Call November 1, 2012 12:00 PM ET

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2012 Bill Barrett Corporation Earnings Conference Call. My name is Regina, and I will be your conference operator for today. [Operator Instructions] Later, we will be conducting a question-and-answer session. [Operator Instructions] Today's event is being recorded for replay purposes. I would now like to the conference over to your host for today, Ms. Jennifer Martin, Vice President of Investor Relations. Please go ahead.

Jennifer C. Martin

Thank you, Regina. Hello, everyone, and thank you for joining us today. Presenting today are Fred Barrett, our Chairman, Chief Executive Officer and President, who will start of with opening comments; Bob Howard, our Chief Financial Officer, who will review our financial results; and Scot Woodall, Chief Operating Officer.

A few quick notes as usual before we get started. Our third quarter Form 10-Q was filed yesterday afternoon. It's available on our website under SEC Filings. Second, I need to remind everyone of the forward-looking and other cautionary statements provided in our earnings release yesterday, as well as the press release this morning. In addition, during our conversation, we make reference to discretionary cash flow and adjusted net income, which are non-GAAP measures. Reconciliations to the appropriate GAAP measures may be found in the earnings release, which is posted on the homepage of our website.

Lastly, we will be participating in a couple of upcoming conferences: the Bank of America Merrill Lynch Energy Conference on November 13 and the Bank of America Leveraged Finance Conference on December 5. Both are in Florida, so it will be nice to see you there, or you can join us by webcast as both of those conferences will be webcast. And with that, Fred, I'll turn it over to you to get started.

Fredrick J. Barrett

All right. Well, thank you, Jennifer, and welcome, everyone. It's been a very busy but exciting quarter as we executed on our development oil programs, getting those drill bits into our exploration areas and managing our portfolio to assure financial strength and capital focus on superior returns.

We did exceed market expectations for cash flow at $2.24 per share, with production coming in strong at over 31 Bcfe. Oil production growth continued its trajectory, up 13% sequentially and up 80% compared with the third quarter of last year. Let me make it real clear, we have targeted 80% oil growth for the full year, and I expect to hit that target. Our October net oil production was approximately 9,100 barrels of oil per day. Again, that's 9,100 barrels of oil per day.

We have positive results to report in the DJ, the Uinta and the Powder River Basin deep, and Scot's going to provide more details on those activities. But as a geologist, I always like to add my enthusiasm with what I think is really working. And we have a lot of good things that are really working. In the DJ, Northeast Wattenberg area, the rates at our first 4-well pad look very good, averaging over 400 barrels per day on a 30-day IP. Here, we drilled 2 wells into the "B" bench and 2 wells into the "C" bench of the Niobrara, and we're encouraged to see similar results coming from each of those benches. We have drilled and completed our second 4-well pad, where early results are again encouraging. And we're just finishing up drilling on our third 4-well pad. So we're well along our way in this program. Our results in Northeast Wattenberg, combined with the results from our industry neighbors, and we're watching our neighbors very closely, are confirming the prospectivity and the repeatability of this area.

We do have more to learn as we continue to delineate across our block here in Northwest Wattenberg. But all the activity, ours and our neighbors', are confirming the prospectivity and the repeatability of this area. We recognize the potential for tremendous upside and the downspacing of multiple zones and longer laterals, again, as demonstrated by the adjacent third-party activity. The DJ is a very exciting program, and we're diligently working to optimize our investment there.

In the Uinta oil play, we're also very pleased with the ongoing Wasatch-Green River vertical programs. Now, I have said before that it's this vertical program across the basin that is really the primary thrust of exploitation in that basin. That includes the infill development program in the Blacktail Ridge area, the continued extension of that field, our continued vertical delineation in both the East Bluebell and the South Altamont areas. And personally, I am very pleased with what we're seeing across all of those areas.

Highlighting the third quarter, our early results in the East Bluebell area, where we reported yesterday 4 recent vertical wells that averaged more than 1,000 barrels of oil per day, 24-hour peak rates over 475 barrels per day in terms of 30-day IP rates. In addition, our first vertical well in South Altamont, although it's early, looks exceptionally strong in the lease block that is virtually undeveloped. And by the way, we recognized a number of vertical and horizontal wells recently drilled just south of our South Altamont block that are showing very, very strong rates, both vertically, and some very encouraging-looking horizontal wells in the Upper Wasatch. So I'm going to say more about that here in just a second.

With regards to our horizontal exploration activity, we're very encouraged, but we are seeing some diversity of results, which is not surprising given the geologic diversity of these zones. First, our initial Wasatch horizontal in the Blacktail Ridge area was drilled as an infill between existing vertical Wasatch producers. And we're -- as we said in the press release, that we're relatively optimistic, but we do want to step out here and drill a second Wasatch horizontal out of way from existing production south of Blacktail Ridge.

Secondly, our Black Shale horizontal, although it produces oil, it is not performing as strong as we wanted to see it, although we are seeing a clear, sustained oil production, likely due to the shale reservoir and the lack of persistent natural fractures in this immediate area. And then thirdly, we continue to be very pleased with the performance of our Uteland Butte horizontals and are in the process of drilling and completing an ongoing Uteland Butte delineation program through the fourth quarter here.

So to put all these in perspective, all of our horizontal activity to date has been localized in the Blacktail Ridge area. We are very encouraged with the Uteland Butte, as I mentioned. We're optimistic about the Wasatch, as I mentioned. But we still have a lot of work to do as we look out across the basin at our acreage positions in other horizontal prospects. As an example, we recognize very strong oil rates from a recent horizontal Wasatch well drilled by another company just south of our undeveloped South Altamont block as I had mentioned. Now these are the type of rates that suggest big potential for horizontal Wasatch in this South Altamont area. We are seeing reported rates over 750 barrels per day in the Upper Wasatch horizontal, producing at over 60 days. So your take away here is that it's early in our Uinta Oil Program. We couldn't be more excited about the oil resources we control through the vertical type exploitation and delineation program. But we're equally excited about the future potential that we see through horizontal technologies across our acreage positions. There's still a tremendous amount of work to do there.

Switching basins, as we drill multiple horizontal horizons in the Powder River Deep, we continue to see multiple success cases as we move forward. Preliminary results from our first Sussex well are looking good, and we are currently completing our first well into the frontier. I'm optimistic about that as well. In addition to our drilling activities, we've continued to expand our acreage position in this emerging oil play.

Changing gears here, looking forward, we have modified our 2012 capital guidance to include additional leasehold acquisitions made since last quarter, with the total spend expected to be between $900 million and $950 million. Now this amount includes approximately $140 million to $165 million in cumulative leasehold acquisitions and also $38 million in infrastructure buildout at West Tavaputs. In the fourth quarter, our capital run rate will be lower as we are managing our active rigs, which means some downtime and switching certain rigs out for less expensive rigs.

As we look forward towards 2013, we will continue to direct you to a monthly drilling and completion run rate with 8 rigs at approximately $45 million per month until we have more specifics on our plan. We have not finalized our 2013 budget yet. We are working hard on it, but we will announce those plans in January along with our 2012 year-end reserves.

This morning, we announced that we have signed a purchase and sale agreement to sell our natural gas assets in the Wind River, our Powder River Basin CBM assets and a portion of Gibson Gulch asset in the Piceance for $335 million. Portfolio management and the divestiture of certain non-core assets is something we had indicated that we would do, and we're doing it. As we invest in expanding our oil portfolio and high-grading our investment dollars into projects that offer the most profitable returns and long-term growth potential, it is our business policy to monetize the assets at the other end of the portfolio. As described in the release this morning, the proceeds will be used first and foremost initially to pay down debt and then also provide strong reliable liquidity for continued development in the Uinta and DJ oil programs over the next several years.

Secondly, provide greater financial flexibility should low risk opportunities emerge that expand on our core development areas and are consistent with our strategic low risk growth objectives. And then third, keeping the company financially poised should we recognize clear success with our ongoing exploration programs. As you all evaluate the merits of this deal, I think an important observation is to recognize the market value of the Piceance which based on this transaction is put around $1 billion. I expect you all also to look at the impact on production, which is estimated at around 18 Bcfe for next year and also projected operating cash flow, which at the current strip would approximate about $43 million. So the net effect of 2013 cash flow pro forma is about $33 million, which includes interest and corporate level savings. The multiple we are getting for this transaction is about 7.8x projected cash flow, a multiple which is much greater than our corporate valuation, something I think all of you recognize.

Then one last point before I hand it over to Bob. Today, we are a much more focused and balanced company with tremendous upside and excellent financial strength. I couldn't be happier about where we stand today with our portfolio. I'm very pleased with our team's strategic execution and the future growth prospect for our shareholders. Substantial long-term oil inventory through our 2 largely undeveloped Uinta and DJ programs, we now have the oil fairway and runway that our investors were looking for. We also have future gas exposure through our Piceance programs and a significant gas growth engine at West Tavaputs. And the potential for other game-changing growth catalysts in a number of oil exploration plays where our excitement continues to grow.

Again, thank you, all. And with that, I'm going to turn it over to Bob Howard, our Chief Financial Officer, for our financial discussion. Bob?

Robert W. Howard

Thank you, Fred, and I'll start with a couple of highlights from the quarter. This is a good quarter. Production at 31.3 Bcfe. Oil and NGLs made up 29% of sales volumes and 56% of sales revenues. Oil production is up 79% for the first 9 months compared with 2011. As Fred mentioned, we are on track to meet our full year target of growing oil production by 75% to 80%.

Oil production was 14% of total volume for the quarter, which was up from 8% in the third quarter of last year. Our third quarter production helped drive very strong cash flow at $105.8 million or $2.24 per share. Cash flow is up 12% sequentially as we benefited from higher total production, including higher oil production, slightly improved natural gas prices and slightly improved cash operating cost.

To give you a little more detail on our realized prices, as we continue to realize prices that are substantially stronger than posted CIG prices. Third quarter average sales -- average realized price was $6.15 per Mcfe. The CIG natural gas price index averaged $2.55 per MMBtu for the quarter, yet we realized $4.90 per Mcf for natural gas sales, which was supported by an $0.87 per Mcf uplift from our processing Piceance gas for NGLs and $1.05 per Mcf uplift from our hedging program.

Our NGL revenues are tied to Mont Belvieu pricing, and the Mont Belvieu NGL basket averaged $0.97 per gallon in the quarter. And our NGL realizations for Piceance processing equated to $0.83 per gallon in the third quarter. Of note, total NGL sales volumes declined in the quarter due to lower ethane volumes being recovered from the gas stream.

WTI oil prices averaged $92.25 per barrel in the quarter and our oil production realized $84.08 per barrel, reflecting deductions for locations and quality and the benefit from oil hedges of $6.09 per barrel.

Moving to describe our hedge positions. For the fourth quarter, we had 21 Bcfe hedged, roughly 70% of expected production. Natural gas hedges are tied to the CIG Rockies prices that averaged $3.99 per MMBtu and WTI oil hedges averaged $99.92 per barrel. For 2013, we have 64 Bcfe hedged. Natural gas hedges before NGL hedges averaged $3.69 per MMBtu and WTI oil hedges averaged $98.57 per barrel.

Adjusted net income for the quarter was a loss of $9.7 million or $0.20 per share. This quarterly results include $15.6 million of dry hole costs for unsuccessful exploratory natural gas wells in the Paradox Basin, which also computes to $0.20 per share on an after-tax basis. For financial reporting purposes, we incurred a quarterly loss of $52.6 million or $1.11 per share after reflecting an $18.8 million impairment expense related to our dry holes and the unrealized loss on our derivative positions.

Looking at the balance sheet, we ended the quarter with $160 million drawn on our line of credit. In October, our borrowing base was reaffirmed at $900 million based on oil and gas reserves and our hedge positions as of June 30. We ended the quarter with $1.3 billion in principal amount in senior debt. Debt as a percentage of book capitalization was 56 -- 54%, and the ratio of debt to trailing 12-month EBITDAX was 2.7x.

Natural gas property sale, as announced this morning, improved our balance sheet and provided increased financial flexibility. We have frequently spoken about portfolio management, including divesting nonstrategic assets in order to fund our transition to oil, and we're very pleased with the agreement to sell the Powder River Basin coal bed methane, the Wind River Basin gas properties and a portion of our Gibson Gulch for a proceeds of $335 million. As referenced in this morning's release, the transaction includes an 18% interest in Gibson Gulch in 2013, which increases to 26% interest in 2016. This transaction is scheduled to close by December 31, 2012, at which time the sales price will be adjusted to reflect an October 1, 2012 effective date. Due to the closing date in late December, the sale will not have a material effect on our guidance or operating metrics for 2012.

The sale is a good business decision, it makes -- creates economic value. The sale demonstrates the market value of the Gibson Gulch at around $1 billion. We are retaining a majority of that asset, and therefore, the sale provides a benchmark for the net asset value to be ascribed to our remaining majority interest. And at $25 per share, our stock trades at about 4.6x consensus EBITDAX, and we received about 7.8x project cash flow for this transaction.

With that, I will turn the call over to Scot Woodall, our Chief Operating Officer. Scot?

R. Scot Woodall

Thanks, Bob. We continue to direct all of our development and exploration drilling towards oil, and we are solidly on track to meet our targeted 75% to 80% year-over-year growth in oil production and exit 2012 with more than 15% [ph] of our production from oil. We have invested significantly over the last 2 years to build our 2 core oil programs and to establish oil-directed exploration in 3 areas. We will exit 2012 well-positioned for significant growth in oil reserves, drilling inventory and long-term growth in cash flow.

I will discuss today positive results in both the DJ and Uinta Oil Program that continue to demonstrate the potential of these growing and scalable development programs, as well as an update on exploration prospects that offer long-term upside. Let's start with the DJ Basin, which Fred has already highlighted. At the Sebring [ph] pad, which is our first 4-well pad located in the Northeast Wattenberg, we drilled 2 wells in the "B" bench and 2 wells in the "C" bench, a zone we had not yet tested. The "B" bench wells are at an approximate depth of 6,350 feet and the C wells at approximately 6,450 feet, each with approximately a 4,000-foot lateral and 18 stages of fracs. We are particularly pleased with the results. Peak IP rate averaging 712 barrels of oil per day for the first -- for the 4 wells and a 30-day rate averaging 407 barrels of oil per day, and the "C" bench was consistent with the "B" bench results. When we acquired our acreage position in the Northeast Wattenberg area, we evaluated the position based on 3 to 4 wells per section and looked only at the "B" bench. The ability to downspace and to produce from additional horizons provides real upside in this area. We have talked about the success of several of our peers around and adjacent to our position who have downspaced to 16 wells per section, tested the "B" and "C" benches, as well as the "A" bench and the Codell, who have tested extended link laterals -- which by the way is right next door to where our acreage position is, and all of these things are having positive results.

Our results to date are very strong, and I would reiterate again that there's a lot of upside potential here. I will also mention that we had a few questions regarding gas gathering and processing infrastructure in the DJ Basin. We have not yet had any material delays or interruptions in our Northeast Wattenberg area operations. We are operating in an area that has a high oil content compared with the core Wattenberg area, and while we are growing rapidly, we are confident that our production growth will not be materially constrained by delays in natural gas infrastructure.

On the oil side, we market a portion to a local refinery in the Denver area. The remainder is transported by either the White Cliffs Pipeline or by railcar through the use of several transloading sites located in Weld County, Colorado. Again, we are confident our production growth will not be materially constrained by delays in expanding oil infrastructure.

In the Uinta Oil Program, we are seeing steady growth with production in the third quarter up again sequentially by 20%. We placed a total of 17 vertical wells online in the third quarter. The results in East Bluebell and South Altamont have exceeded our expectations. In the Blacktail Ridge area, the average well result has met our expectations. In regards to our horizontal well results, the Wasatch well was drilled in a section of Blacktail Ridge with existing vertical production. We think we experienced depletion in that well. Our next Wasatch horizontal test will be in an undeveloped area with original pressure. The Black Shale well drilled in the Blacktail Ridge horizontal does not look economic to date. We will reassess the Black Shale potential in Blacktail Ridge, and will more than likely drill another Black Shale test in a different part of the basin. Remember, this is a technical play as the geology changes across the basin, so we'll continue to evaluate whether horizontal technology is appropriate for other areas of our acreage position.

We have restarted our Uteland Butte drilling program. The original wells continue on trend for approximately 300 barrels of oil equivalent EURs, and we expect to drill 4 Uteland Butte horizontals in Q4 of this year and into the first quarter of 2013.

In regards to refining capacity in the Uinta Basin, we continue to explore a variety of options and do not have any new news to report. However, we continue to remain confident that there's enough marketing options to meet our growing oil production volume.

Turning to exploration. We are liking what we have seen to date in the Powder River Deep program. The Shannon well reported on last quarter had a 24-hour IP rate of 523 barrels of oil per day and a 30-day average rate of 429 barrels of oil per day, with 90% of it oil. The Sussex well, which does not yet have a 30-day production, had a 24-hour IP rate of 598 barrels of oil per day and a first 20-day rate of 445 barrels of oil per day. We will drill 3 more wells by year end, 2 in the Frontier and one more Shannon well. In the capital guidance, we included an acreage acquisition of about 3,400 net acres in that area that closed in October. Also in coming months, we should complete our first South Alberta well, and drill 2 San Juan Basin wells.

Turning to capital. We did raise the midpoint of our guidance by $50 million, primarily as a result of adding additional bolt-on acreage, that acquisitions made in Q3 are anticipated in the fourth quarter. Our fourth quarter capital run rate will be lower than previous quarters as we're replacing some of the skid-able rigs that we currently are using in the Uinta and DJ Basins, which held left-over rigs from the Piceance and West Tavaputs programs, with more appropriate and less expensive rigs. As a result, there will be a downtime and fewer than 8 rigs active for some parts of the quarter. Additionally in Q3, we finished our remaining completion program in Piceance, which will result in a lower Q4 capital spend rate.

Production guidance of 118 to 122 Bcfe is unchanged, and we are on track. Guidance for LOE, transportation and G&A are either lowered or coming in at the low end of the original range. We're in the process of working on our 2013 capital program, and as Fred mentioned, we will announce our plan in January of 2013.

That wraps up my comments. I'll turn the call back over to Jennifer.

Jennifer C. Martin

Thanks, guys. Regina, if you'd like to go ahead and open up the call for questions, please.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question today comes from the line of Ryan Oatman with SunTrust.

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

Want to focus on the Niobrara here. Can you speak to the design of that pad, were the wells drilled in the B space apart on 80 acres spacing, 40 acres spacing, and then similarly with the C? Just trying to get a feel for the ultimate potential for this Niobrara asset.

R. Scot Woodall

Sure, the spacing of that one, Ryan, was on 160. So there's 4 wells in a 640. I guess technically if you look at it, you could state that the B is on 320 and the C is on 320. But it's 4 wells in this section, alternating Bs and Cs.

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

Okay, thank you for that. And then when I look at the combined West Tavaputs and Piceance Basin output disclosed in the press release here versus the 3Q average, it looks like their current production is off 3% to 5%. Is that sort of a fair decline estimate for the next few quarters here? And then, I guess, kind of a follow-up with that, we had gas prices rebound, and if that decline is sort of representative, what are your thoughts on putting a rig there to protect that production and cash flow into 2013?

R. Scot Woodall

A couple of things there, Ryan. I would say that the 3% to 5% decline in gas rate is -- it will probably be a little bit steeper than that. And if you remember, we completed Piceance wells up through the end of September. And so now that you're into November, we will have no new wells coming on in Piceance. And I think adding some Piceance wells in Q3 probably flatten that decline of Piceance a little bit. So I would expect the Piceance decline to be a little steeper when you look at the production in Q4. In terms of -- yes, we like the return of higher natural gas prices, and obviously we like what that all looks like. In terms of capital allocation, that's just something that we're going to have to look at. And we're going to have to model what we think gas properties' rate of returns are in connection of looking at what the rate of returns of our oil properties are. So we'll have to look at those 2 things in conjunction with each other.

Operator

Your next question today comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I know you don't want to be specific on 2013, but just looking kind of backwards here on 2012, you outspent cash flow here by about $450 million, $470 million or so in the first 3 quarters. And the property sale here is going to do the bulk of that. But given some of the one-off issues that you highlighted with why 20 -- why fourth quarter CapEx will be lighter, can you just talk directionally at how we should think about 2013 capital levels relative to the fourth quarter, and then how you think about CapEx versus cash flow next year, acquisitions and divestitures?

Robert W. Howard

Okay. Well, thanks, Brian. Let me make a couple of points there. We noted in our call this morning that as we look forward, hypothetically at this point, an 8-rig run rate is kind of $45 million per month. Now that's drilling in completion. And so as we look at 2013, there's a few things we need to finalize with the budget, whether it's related to exploration or facilities. But I think that run rate is a good proxy at this point. We'll deliver the final details in January as to that end. You should not look at this sale as something that means we are going to maintain a similar type budget next year. Our objective is to clearly be more aligned with cash flow. But again, we will disclose that budget in January. As far as acquisitions and opportunities next year, we're always opportunistic within -- especially in these development areas. There may or may not be opportunities to expand our existing core development areas, but if there are and it's accretive to our strategic objective to grow high return projects in our development areas, we'll take a look at them. But we certainly, right now, are in a much better financial position in terms of those development programs, given the sale of these projects to direct that capital into high return, high growth projects.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then in the Wattenberg area, can you just put into context kind of how you think your delineation or what you still have left to delineate, and when you think about a program, where do you ultimately see the possibilities in terms of a rig count or an annual well count before you hit up against constraints?

Fredrick J. Barrett

Well, as we move east, we need to delineate what's happening as we move east where we've been drilling a number of wells on the northern side of our block, on the southern side, in the middle to the east to the west, and literally have just begun that process in looking at initial rates, et cetera. So we've got a little ways to go, but again our point is that we do -- we're also watching industry activity immediately adjacent to our acreage block on the west side and also to the north. And so I think you're looking at a couple of quarters before we really start to get our arms around a number of these positions within the block and how we finalize the delineation. But up to this point, we are very encouraged with the data that we have and with the data that the industry offers adjacent to our leases. Scot, anything to add?

R. Scot Woodall

We're early. Remember we just started drilling in August.

Operator

Your next question is from the line of David Tameron with Wells Fargo.

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

Whoever, Fred or Scot, whoever wants to take this. Can you just talk about between the "B" and the "C", what are the differences that you see in the Niobrara? What differences between the 2 zones?

Fredrick J. Barrett

Well, we're not seeing a lot of difference between those 2 zones, and I think industry are -- the offsetting activity that we're seeing is indicating that those 2 zones are somewhat equivalent in what they have to offer in terms of produce-ability, that's our understanding. We've not even begun to look at the Codell, and we've not even begun to look at the "A" bench. But we clearly see a significant potential at this point in the "B" and the "C" bench.

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

Okay. And you said -- I know you talked about them being more oily, but can you give us an indication throughout those 30-day rates, what's the oil count?

R. Scot Woodall

We're running about 75% oil, Dave.

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

Okay. And the rest is? Is it 20% gas, 5%, 10% NGL?

R. Scot Woodall

Yes, we're talking -- I'm thinking more 2 streams. I'm thinking 75% oil and 25% gas and then, yes, you get an NGL on top of that.

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

Okay, all right. That's helpful. And then moving back to the Uinta, and Fred, you talked about the majority of the growth coming from the -- let me ask if I heard this correctly. The majority of the growth is going to be coming from the verticals as far as what you have going forward. And then you have 4 to 5 rigs out there. Is there 1 rig drilling horizontals, the rest are on verticals? Is that the right way to think about that?

Fredrick J. Barrett

Yes, at this point in time. Another way to look at this is we could look forward on our vertical program, and you're going to have to drill that vertical program regardless of what happens horizontally. So that we look forward and we don't necessarily need a horizontal program to work. We don't need a horizontal program to work. All that we're doing horizontally is maximizing the overall recovery 3-dimensionally within the Uinta oil basin. But that said -- and so the vertical program, because of the individual lenticular discontinuous sands require that you drill those vertical wells, we do recognize a number of the more continuous zones that I think there's a strong likelihood. You will see the emergence of multiple horizontal programs. And I believe that we know the Uteland Butte is present across our Blacktail Ridge, Lake Canyon area. We have defined that accordingly. We believe that based on other industry activity that there's some very, very strong upside related to the horizontal Wasatch over in our South Altamont area. I think you're going to probably -- I'm going to guess you probably have a decent program in the Wasatch over in the Blacktail Ridge, Lake Canyon area. We still need to confirm that, but I think we have enough optimism from the first horizontal that, that's going to be the case. We'll finalize that. And then we have a number of other horizontal intervals that we just don't talk about yet. For example, over in East Bluebell. And so you don't need a horizontal to make this work. We're seeing wonderful growth via the verticals. But along the way, we'll continue to do -- see where the horizontals work and continue to maximize the resource recovery out of this basin.

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

Okay. And just to chase that point a little bit, in the press release, you have some language that just talked about changes in composition across the acreage position. Are you just saying that -- are you just talking about the variability across that and kind of similar to what you just said, "Hey, horizontal is going to work in some spots and not in others."

Fredrick J. Barrett

Exactly. Yes. As an example, David, we look at the Black Shale, a very rich source rock. A lot of oil in there, and we're seeing oil production out of our horizontal in Blacktail Ridge not at rates we had hoped for. But as you move east across the basin, that zone becomes more dolomitic. It's more -- it becomes more of a carbonate as you move from east to west. Where we tested it, it's more of a true shale. And so who knows, maybe that works more effectively further to the east. The Wasatch, may be more widespread. The Uteland Butte, we think, is going to be a fairly regional play. And there's a few other zones that might work over in the East Bluebell, and they may not work in the Blacktail Ridge, Lake Canyon areas. So it's early, and we -- but we're excited about the horizontal potential.

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

Okay, 2 more questions on the Vanguard transaction. First of all, congrats on getting that done. But second, is there any type of drilling commitment, any price threshold? Anything you have to do going forward as far as, I guess, development dollars and any type of capital you have to spend there?

R. Scot Woodall

No, David. There is no development capital obligations with the transaction.

Operator

Your next question is from the line of Jeff Robertson with Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

Fred, you mentioned production rate of about 9,100 barrels of oil, I think, currently. In the release, between the Uinta and the DJ, it looks like you hit 8,300. Are there some wells in your 9,100-barrel a day number that are additive to what's in the release or additive to what you're all doing in the third quarter?

R. Scot Woodall

Yes, I think we just continued to put some wells online, Jeff, that is helping us there. I think when we're starting to do a few of these DJ locations as 4-well pads, obviously you kind of get things in chunks a little bit. And so I think we put on another 4-well pad that you're seeing come online in October.

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

And Scot, is that pad one you all just don't have enough history on to talk about the rates yet like you did on the Sebring pad?

R. Scot Woodall

Yes, I mean Fred used the word very encouraging, so I guess we'll stick with those words for now. But yes, we don't have 30 days yet, so we're not disclosing the actual numbers. But it looks good.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay. And secondly, on capital, just back to that $45 million a month that gets to about $550 million for the year with the 8 rigs. Fred, does that include exploration or facilities, or do you have an amount that might be -- go on top of that for some of the exploration prospects you hope to test next year?

Fredrick J. Barrett

No, the $45 million a month was drilling in completion run rate. And so we're -- although we haven't finalized it, and we do have results coming in from exploration, but as a proxy, say, 10% of cash flow and then some additional facilities that we may need to put in, in the Uinta Oil Program. But again -- and those were the details that we're finalizing that I spoke of in our press -- in the transcript.

Jeffrey W. Robertson - Barclays Capital, Research Division

Does that get you up to the roughly $600 million to $650 million if you include some of that, which is I think the number you all have talked about in the past?

Fredrick J. Barrett

Well, let us finalize those numbers, Jeff. We don't want to -- but I think the bulk of that program is related to the $45 million a month. And so we'll finalize those details. We don't want to corner ourselves at this point.

Jeffrey W. Robertson - Barclays Capital, Research Division

And lastly, back on the DJ, Fred or Scot, can you all talk about when you think you'll be in a better position to quantify more of what you think the upside will be across your acreage?

R. Scot Woodall

Yes, I think, Jeff, that's going to be kind of part of the year end process this year. So we've been working very closely with our engineering audit company that we use. We've been working with them the last month or 2. And so yes, I think we hope that towards year end, early next year, that we'll start to put out some EURs, some location counts and some of those types of things.

Operator

Your next question comes from the line of Pearce Hammond with Simmons & Company.

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

On the transaction with Vanguard, the production that you highlight for next year, the 15 million cubic feet equivalent a day, how much of that is NGLs?

R. Scot Woodall

That is actually -- those numbers, Pearce, were 2-stream.

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

X

Right. And then, what would be the breakout of the production mix and if you -- I'm just trying to get a sense of how much, obviously Gibson Gulch produces NGLs, what the mix looks like.

R. Scot Woodall

Yes. I don't have that sitting here in front of me. Maybe that's something that Jennifer can follow-up with you later or something.

Jennifer C. Martin

Yes. I'm happy to follow-up on that. You can see that the buyer actually published some numbers with a breakdown based on current production.

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

Great. And then going back to the DJ, what are your well costs on those -- on that 4-well pad?

R. Scot Woodall

We are doing pad drilling. We're about in that $4.5 million range. When we're doing single wells, they're a little bit higher than that. But those wells were about $4.5 million.

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

Great. And then as you look out, as you do your budget planning for next year, how do you see service cost trending across your portfolio?

R. Scot Woodall

Yes, we're seeing a little bit. And what I mean by a little bit is probably about around 5% decrease in some of the services.

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

And then finally, in the Uinta, you mentioned you're still working on some takeaway capacity refinery agreements. And I know that's been under way for a while. Just curious what's probably the biggest sticking point to getting one of those transactions done.

R. Scot Woodall

I think it's just trying to find the right balance for our company versus the party that we're working with, and probably what I mean by that is almost any of the options requires some sort of capital outlay by the third party that we're negotiating with and what kind of commitments do they have need for a company like ours to outlay that capital. And most of the time, that comes to a volume commitment and that volume commitment comes with penalties. And so there's a balance to how much volume commitment and how much dollars per barrel penalty a company like us is willing to put forward on a multiple-year transaction. So I think it's meeting the right place in the middle that allows the third party to invest their capital and to get there appropriate returns, as well as not overcommit from our standpoint as well.

Operator

Your next question is from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

You speak to a multiple of close to 8x on projected cash flow with respect to the divested assets. Yet, your stock price continues not to perform well, especially today. Does that prompt you to take different measures to increase shareholder value? And where does the share buyback rank?

Fredrick J. Barrett

Well, Dan, we -- the sale of these assets as you bring up, I think, does highlight some -- I think some very, very strong attributes related to what obviously the market is willing to pay for non-core assets in our portfolio. We look at the Piceance Basin, and although we don't have an exact figure for that basin, I think the cash flow multiples are even higher for that basin. I think the earnings miss, the dry holes and the impairment probably impacted the share price today. But in terms of looking forward strategically, although we always as a company as a matter of exercise, look at a number of strategic alternatives, right now, we are focused on our oil development programs in the DJ and the Uinta Oil Program. We think we have 2 great assets there. We're excited from an exploration standpoint with our programs. We stayed opportunistic. We think there will be other opportunities as we look forward. And as gas prices improve to the extent we think it's worth putting a rig back out of work, we have some great assets there that we can continue to grow reserves and production growth. So we feel extremely good about where we're at. And we'll continue to execute and deliver our budget for 2013 in January.

Dan McSpirit - BMO Capital Markets Canada

Okay. And can you speak to the permitting process in the Powder River Basin?

R. Scot Woodall

It's largely federal, which takes a little bit longer than on state land. So it probably is a 6- to 9-month type of process. But it's something that is manageable if you kind of get your act together upfront. I would say that we probably have more than a dozen permits in hand that we could utilize next year if we chose to.

Dan McSpirit - BMO Capital Markets Canada

Okay. And turning to the Niobrara, what is the NGL yield there, barrels per million, and the shrinkage on the gas? On the last batch of wells.

R. Scot Woodall

Yes. We're selling everything on a percent of proceeds.

Robert W. Howard

About an 1,800 MMbtu equivalent kind of...

R. Scot Woodall

Okay. They're saying about an 1,800 MMBtu equivalent.

Fredrick J. Barrett

And that's a POP contract.

R. Scot Woodall

Yes. And we're selling everything on a percent of proceeds.

Dan McSpirit - BMO Capital Markets Canada

Okay. And what is the decline -- base decline on natural gas production pre-imposed the divestiture?

R. Scot Woodall

Not sure if I got a good answer for that one.

Jennifer C. Martin

We have talked about production going down about 15% to 20%, just kind of based on that hypothetical 8-rig program. And in this case you would just take the gas production projection of about 18 Bs off of that.

Dan McSpirit - BMO Capital Markets Canada

Okay. And lastly, on the Sussex well, it's only one well, but a peer that is drilling in that part of Wyoming speaks to recoveries of over 400 MBOE per location. Does this one well, recognizing you've only got a 20-day rate on that well, 20 days of production history, does that support a 400 MBOE recovery EUR?

R. Scot Woodall

I think it's way early for us to talk and quote on EURs. Obviously, we watch what the other activity is around us, and their results look very economic. And that's what we're trying to duplicate on our lands.

Operator

Your next question comes from the line of Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

I believe on the last quarter's conference call, you stated that you could still have an 80% growth in 2013 on oil production if you drop the development CapEx to $550 million. I know you're going through the preliminary process right now of setting the budget for 2013. But just kind of wanted to get your sense if that 80% number still seems valid.

R. Scot Woodall

Yes. Preliminarily, I'd say yes.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. That's good. And then on the exploration front, if that's assessed now in the Shannon and the Sussex in the Powder River Basin, just curious of how much more time you think it will take or wells to be drilled before you could really have the confidence that you got a development program that you could really put to work?

R. Scot Woodall

It's still early. That's still just a couple of wells. So I think we've got to have a few more tests in there. But obviously you have to remember that a lot of the horizontal activity that we're doing is in a month's vertical test as well. So it does give you a little bit higher degree of confidence than if you had just gone out and drilled 1 horizontal well with no offsetting vertical test. But since we have some vertical tests, it gives you a little bit more confidence. But I don't think we're quite yet to start quoting EURs or number of locations or things like that. You need to give us a few more tests underneath our belt before we get to that point.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. But that's -- is that something that largely by what do you think, middle of 2013 you'll have a great idea of where you are there? Is it earlier end of Q1, and whether it's a go or no-go in terms of a large scale development program?

R. Scot Woodall

I probably like more the middle of next year, probably. Sounds like a better timeframe for us to get some solid 30-, 60-, 90-day well results, look at some EURs and assess our position.

Operator

Your next question is from the line of Ryan Todd with Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

I got a couple of questions for you. On the -- you may have mentioned this earlier and I missed it, but I know you've talked about an 8-rig program for next year. Given the recent drilling results you've seen in the DJ Basin and in the Uinta, I mean what are -- are you leaning one way towards -- or the other towards shifting maybe some of those rigs out of Uinta and towards the DJ?

R. Scot Woodall

I mean, I think that's a possibility, Ryan. When you look at things preliminarily, if the DJ meets our expectations, it probably has a higher internal rate of return than the Uinta properties. And so it might say that's a logical shift to have happened at some point. You have to remember, we're still in the process of de-risking our acreage, and so I wouldn't put all of our acreage in a de-risk category. And so we kind of have to get some well results before we're ready to make that type of a switch. We're encouraged in both areas, and we get very acceptable rate of return in Uinta. But purely, if you're looking at capital allocation, if the DJ performs as we think it will, it might receive a higher capital allocation in 2013.

Ryan Todd - Deutsche Bank AG, Research Division

Is there -- I think from a -- I know somebody mentioned infrastructure earlier. I mean, in terms of if you were to fill that from a de-risking point of view, is there other limits other than just de-risked acreage to the number of rigs you can run the DJ, making it run 4 or 5? Or do you start to run in the infrastructure limitations that will prevent you from going any higher?

R. Scot Woodall

Right now the way we look at it, 2013, I don't think that we'd have any other restrictions that would come into play.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And if -- I mean, if we look at your 2012 spending, I mean you had some pretty chunky spending this year in terms of infrastructure with the Tavaputs infrastructure, then you've done a decent amount of acreage purchases as well. I mean if we look forward to 2013, at least on the infrastructure side, is there anything that we should expect in terms of large-scale infrastructure spend that we can expect comparable to what we've seen in '12?

R. Scot Woodall

I think it's early to make that comment yet. We still got to kind of figure out where first we're allocating our D&C capital between the 2 basins and then look to see if any of it requires infrastructure. In most of these 2 plays, we want to talk Uinta oil and we want to talk DJ, we're selling at the wellhead. And so the infrastructure requirements are much smaller than what they are if we go back to the days when we were active in Piceance and West Tavaputs. We owned all that, own compression and all of our own infrastructure and gathering. So in theory, you would say that if you're selling at the wellhead, you're infrastructure cost should be lower on a go-forward basis as we allocate our capital to those 2 plays.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. That's helpful. And then one last one, I know somebody hinted at it earlier. From -- if you're allocating capital on a -- based on a return on capital employed, I mean is there a gas price where your -- where some of your better gas properties out there in the Piceance or West Tavaputs, would they start to compete with Uinta? And when will that be?

R. Scot Woodall

That's a fair question. I'm not exactly sure what that price is. But kind of what I said a little bit earlier is you also have to look at what your oil forecast is. And there are some very great growth opportunities, reserve add opportunities, production growth opportunities in both West Tavaputs and Piceance, and they start to generate attractive rate of returns, probably in that 450-plus type of a price range. But we're going to have to balance that with what the oil price is as we look at the capital allocation.

Operator

Your next question is from the line of Joe Magner with Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

I'm not sure if I missed it earlier, but can you maybe talk about where the dry holes were drilled and where the impairments were seen, and what that implies for some of those gas projects that have been in the mix over the last few years?

Fredrick J. Barrett

Yes, Joe. Those were 2 kind of follow-on -- those were 2 follow-on wells in the Yellow Jacket area, and I would just note that we have not -- we never finished completing those wells. But we felt just on the -- at least what we are seeing on the initial stages that we go ahead and expense those wells prior to being done. And it is in the NGL window in the Yellow Jacket area. We still have plans via our partner to test the oil leg in that program. And as a follow-up to that, that in turn led us to the impairment on the acreage in the NGL window.

Joseph Patrick Magner - Macquarie Research

Okay. So both were tied to the Yellow Jacket though?

Fredrick J. Barrett

Yes.

Joseph Patrick Magner - Macquarie Research

Okay. And then you touched on, I guess, the gas price level that you would need to see for returns to be competitive in Tavaputs and the Piceance. But are there any other obligations, acreage leasing, takeaway commitments that might cause you to revisit those plans prior to perhaps seeing a price level of 450 or higher?

R. Scot Woodall

No, not really, Joe. Everything, really, in Piceance and West Tavaputs is HBP.

Joseph Patrick Magner - Macquarie Research

Okay. Shifting over to the DJ, the results from the pad testing definitely looks encouraging. How much -- I guess, going forward, what's the balance going to look like between how much of that you can really do versus ongoing delineation, either new acreage or new zones?

R. Scot Woodall

I don't have enough to have a good split exactly for you, Joe. We have multiple 4-well pads that we're drilling, which I would probably put that in the core Wattenberg area. And then we're doing single well delineation on some of the new acreage that we have up in the Northwest Wattenberg. And I'm not sure exactly what that allocation back and forth is, but that's kind of what we're doing right now.

Joseph Patrick Magner - Macquarie Research

And I guess will there also be some delineation taking place within the core as well? Different zones and Codell and...

R. Scot Woodall

Perhaps, I would probably think all that will be done from pads. We feel pretty confident based on our initial results and the activity around us that I doubt we'll do single well delineation things. I think you may see us on a 4-well pad test a "B" or test to an "A" or a "C" or a Codell or something, but it will be part of a 4-plus well pad type of development.

Joseph Patrick Magner - Macquarie Research

Okay. And then on the Vanguard transaction, with the step up in working interest over time, how should we think about the, I guess, go-forward impact on production cash flows? Are both of those going to be stable? Are they going to be increasing over time? I guess, how does that work out in terms of the math?

Robert W. Howard

We expect that the increase or the effect on production would be increased. In other words, if we have a declining production base and an increasing interest that they're owning that we would have an increased reduction in production over the period of time on those properties. We will give guidance on that. That will be worked into any guidance numbers that we give for 2013, and I think you need to do then that to drive the -- any effect on EBITDAX or cash flow and at least operating expenses. So I think -- Jennifer mentioned earlier some of the numbers we were expecting for 2013 just on what we've been talking about before, we'll give more specific guidance in late January as to how that affect -- how that will affect us for 2013.

Operator

Our final question today comes from the line of David Magruder with Knighthead Capital.

David Magruder - Knighthead Capital Management, LLC

First is regarding what do you expect on the net proceeds after taxes and fees and working capital adjustments from the asset sales?

Robert W. Howard

We know that the cash taxes on the asset sales will be very minimal. We have some basis in the properties, of course, but we also have $125 million net operating loss carryover that we carried into the year. And so expecting a little bit of AMT tax, a little bit of state tax, in the range of much less than $5 million, probably in the couple of million dollars range for cash taxes related to the sale. So it's kind of our starting point. And then of course, we can look at whatever the tax effect may be. But we're somewhere in a couple million dollars of taxes, so the rest of that should be proceeds.

David Magruder - Knighthead Capital Management, LLC

Okay, great. And then I'd imagine as noted in the release that you're going to pay down the revolver fully. And then, would you -- what would you do with the rest of cash? Is it to fund the CapEx going forward or do you think that you want to delever with buying back some bonds?

Robert W. Howard

Well, with the activity we can do there, we think that much of the proceeds will be used to pay down the revolver down to 0 by the end of the year. We have continued to borrow some money as we get into the fourth quarter as we continue to run our business. And beyond that, as far as buying bonds or something of that size, it's not an action we've fully contemplated to have an answer to right now.

David Magruder - Knighthead Capital Management, LLC

Okay. And when do we expect -- or do you have an idea of what the borrowing base will be? Is there an automatic redetermination when the sale closes?

Robert W. Howard

There will be a redetermination. We have not worked that number out with our neighbor. We're expecting somewhere in the $200-million range would be the effect of the borrowing base from the properties being conveyed.

David Magruder - Knighthead Capital Management, LLC

Okay. And then I also noted, it looks like this quarter, you did a sale leaseback for some of the facilities infrastructure. Is there -- do you foresee additional opportunities like that in the assets or is that going to be pretty much the big one?

Robert W. Howard

On the sale leaseback, we put most properties or most of the tangible assets that are eligible for that type of transaction into the sale leasebacks. So there's nothing -- not a huge additional opportunity that's available to us.

Operator

Ladies and gentlemen, this does conclude our question-and-answer portion today. I'd like to turn the call back over to management for some closing remarks.

Jennifer C. Martin

We'll just say thank you, all, for joining us, and feel free to give us a call if you have some more follow-up questions.

Operator

Ladies and gentlemen, thank you so much for your participation in today's presentation. You may now disconnect. Have a great day.

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