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Bill Barrett (NYSE:BBG)

Q1 2013 Earnings Call

May 03, 2013 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

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

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

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

Jeffrey W. Robertson - Barclays Capital, Research Division

Michael Schmitz - Ladenburg Thalmann & Co. Inc., Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Dan McSpirit - BMO Capital Markets U.S.

Operator

Good day, ladies and gentlemen. Welcome to the Bill Barrett Corporation First Quarter 2013 Earnings Call. My name is Sheverly, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. At this time, I'd like to hand the presentation over to your host for today, Ms. Jennifer Martin, Vice President, Investor Relations. Please proceed, ma'am.

Jennifer C. Martin

Thank you, Sheverly. Good morning, everyone, and thank you for joining us. Presenting today will be Chief Executive Officer, Scot Woodall; and Chief Financial Officer, Bob Howard. Before we get started, I want you to you know our quarterly report on Form 10-Q was filed a few minutes ago and either is or shortly will be 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, 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 few upcoming conferences: I will be at the ISI conference next week, Bob Howard will present at the BAML Leverage Finance Conference the following week and Terry Barrett and I will be at the SunTrust Play by Play conference at the end of the month. We look forward to seeing many of you in the coming weeks. And with that, I will turn it over to Scot.

R. Scot Woodall

All right. Thank you, and good morning. First quarter operations were on track with our full year guidance and on track with our strategy to drive growth in the Uinta Oil Program and to realize value through delineation and execution in the DJ Basin. Our team successfully achieved the implementation of measurable operating efficiencies and improvements at each of these 2 basins.

At the DJ, our confidence continues to build as our understanding of the geology and our application of technology continues to improve. We are ready to increase the pace of our activity to 3 to 4 rigs through the remainder of 2013 and now plan to test certain comp sets that are proving successful in the area. More on that in a minute.

I want to comment on a number of one-time items that were incurred in the first quarter. Decisions we made to discontinue exploration funding of certain projects, we believe, are right for our shareholders, yet negatively impacted our Q1 results. Several one-time costs were also incurred in the quarter. None of these one-time costs impact our 2013 plan or guidance. Bob will review these costs in more detail later.

So let's move onto the DJ, or more specifically, the Northeast Wattenberg area. First, we reported results from one new well located on the eastern portion of our acreage. The well had a peak IP rate of 700 barrels of oil equivalent per day and a 30-day rate of 413, consistent with our expectations at this preliminary stage. This well was completed with a 3,800-foot lateral and 17 frac stages and was completed with a larger frac size than some of our earlier wells. As planned, our activity in the DJ was nominal in the first quarter as we switched out rigs and realigned our program based on results by us and others. We continue to gain confidence in our Northeast Wattenberg area and are now ready to increase the pace of activity.

I will emphasize that our mapping across our acreage position looks consistent on all geologic parameters. We have 2 rigs active in the Northeast Wattenberg area right now, and we'll increase that to 3 to 4 rigs throughout the remainder of the year. To date, we have made improvements in our drilling costs and our lateral location placement. We have increased our frac sizes and continue to optimize our designs. We are working to optimize our flowback and artificial lift techniques. We are working with our gas gatherer to meet our infrastructure needs.

Clearly, this is a huge focus for the company, and substantial progress has been made in the few short months that we have been active in this area, and I am pleased with our progress to date.

Our plans for 2013 are still to drill 65 wells in our program, targeting primarily the Niobrara B bench. However, we have updated this year's plan to include more pad drilling. The pad drilling will be on 80-acre spacing, 8 wells per section. We will also include some C bench wells in the mix, and we will also drill at least 2 Codell test. We also plan to drill one extended lateral. As we ramp up further in June and have elected to do more pad drilling, this will result in production growth being back-end loaded towards the fourth quarter.

We expect the economics of the DJ Basin to be the best in our portfolio, offering a 65% rate of return at a $90 oil price. I look forward to speaking to you about our further successes as we execute on this plan.

At the Uinta Oil Program, we continued to make strides in drilling and completion cost reductions and driving operation efficiencies. Through changes in completion design and technology, we are reducing our D&C cost by $400,000 per well, bringing well cost down to the $3.3 million range. Our saltwater disposal system has led to LOE reductions of approximately 30% year-over-year. First quarter drilling concentrated on the East Bluebell area, where our early results are exceeding our expectations.

We are in the process of completing 2 80-acre spacing test which were drilled in the Blacktail Ridge area. We will need to run long-term tests here, so we will not have results until near year end.

Of note, the 2013 wells drilled for the DJ and Uinta Basin are largely unchanged, with the Uinta oil program activity stronger in the first half of the year and the DJ activity stronger in the second half of the year.

In the Powder River Deep program, we reported very strong results from the last 2 wells. These were both frontier wells. Individual well results continue to look promising. These wells were completed with approximately 4,000-foot laterals and 19 frac stages. This remains an exciting area for oil development. Our results have indicated success in the Shannon, Sussex and Frontier zones.

As Bob will discuss in a minute, progress is being made on maintaining our debt levels at or below 2012.

As I reflect back on the first quarter, it was a quarter full of change and transitions. I could not be more pleased at how our organization has responded to this change and how committed and focused they are on implementing our strategy. I look forward to providing future updates as we continue to improve on the execution of our portfolio.

I will now turn the call over to Bob Howard.

Robert W. Howard

Thank you, Scot, and good morning, everyone. As Scot reviewed, we had a solid quarter and remained on track with our expectations for the full year. Highlights from the first quarter include three-stream production was 21.2 Bcfe, which is in line with the consensus of the 17 analysts that cover the company. Oil production for the quarter was up 67% over the first quarter of 2012. Oil production was 22% of total production, and oil and natural gas liquids were 31% of total production.

Discretionary cash flow for the quarter was $63.6 million or $1.34 per share. Excluding a couple of one-time costs detailed in the press release would add $3.8 million or $0.08 per share, which would put cash flow at $1.42 per share, which is in line with consensus numbers.

Production, capital expenditures and operating costs remain on track for our full year guidance. While the details of the results are found in today's earnings release and our first quarter Form 10-Q, I'll take a few minutes to clarify the one-time items and changes in reporting included in the first quarter.

The first quarter included $1.2 million of LOE costs or $0.06 per Mcfe associated with testing and pipeline reclamation work following the compressor station fire late last year at the West Tavaputs area. These charges are one-time costs that were not covered by our insurance policies.

First quarter LOE also included major compressor overhauls in the Piceance Basin. The LOE cost related to both the West Tavaputs work and the Piceance compressor overhauls will not be recurring costs this year, and we remain on track for a full year LOE guidance of $62 million to $67 million.

General and administrative costs for the quarter included $4.6 million related to the CEO transition that includes $2.6 million of cash costs. This total is slightly above the $4 million that we included in our original G&A guidance. These costs are substantially complete for the year, and we continue to expect that 2013 cash G&A will be between $50 million and $54 million.

During the first quarter, we terminated a drill-to-earn agreement in the San Juan Basin for which we recorded a $4.6 million abandonment cost for the quarter. This charge impacted both pretax net income and pretax adjusted net income by approximately $0.10 per share.

Worth noting that in 2013, we began reducing oil revenue in the Uinta oil project for trucking charges that are deducted by the purchaser in determining the net amount that we paid for our oil -- that we are paid for our oil production. This change was made to be consistent with the oil sales arrangements that do not separately disclose those costs. Previously, those trucking cost deductions were reported as a component of gathering, transportation and processing expenses.

As a result of the change, our realized oil price for the first quarter was reduced by approximately $2 per barrel compared to the previous method. We have reduced gathering, transportation, processing guidance to reflect this change on an ongoing basis. This change in reporting for oil trucking charges does not have any impact on net income or well economics.

With respect to DD&A expense, we update our depletion calculation every quarter based on activities and production in each of our producing areas. The DD&A rate for this quarter is the most up-to-date estimate that we have for our future results. Our DD&A rate for the first quarter is $3.22 per Mcfe compared with $3.32 per Mcfe in the fourth quarter of 2012. On average, it appears that the net income estimates by the investment community for the first quarter were applying an estimated DD&A rate of $2.93 per Mcfe to our results. Due to the nature of our business, we expect that the DD&A expense related to oil production will be higher than the DD&A cost related to gas production.

To reiterate Scot's earlier comments, the results for this quarter reflects certain transition costs as we continue to refine our focus through our 2 oil development programs while scaling back in all other areas.

One-time items that we incurred in the quarter are not expected to detract from our operational performance or execution of our 2013 plan.

Moving on to the balance sheet. We recently completed our spring bank redetermination under the credit facility, and as expected, our borrowing base was reaffirmed at $825 million and total commitments from the bank lenders remain at $900 million.

We ended the quarter with $25 million drawn on the line, which leaves us ample liquidity for development plans and financing needs.

We remain committed to keeping our year end 2013 debt at or below the debt levels at the end of 2012. We're actively pursuing property sales with the expectation that we will meet funding requirements through portfolio management.

At this time, we are preparing a formal data room and marketing process for certain assets, which could include outright sale or other methods of monetization, and we've begun sharing data with certain eligible buyers. We have received significant interest in sales, joint ventures, other monetization options of certain assets, including the Powder River Deep oil program and our West Tavaputs gas field. Additionally, we're reviewing proposals from third-party advisers to lead the sales process. We expect to complete the sales process in the second half of the year.

That completes our prepared comments. We'll now open the line up for questions.

Question-and-Answer Session

Operator

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

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

I wanted to talk a little bit more strategically here. Can you talk about the decision to shift from the Uinta Basin to the DJ Basin and what informed -- the company is making that decision?

R. Scot Woodall

From a straight look at internal rate of return, if the DJ Basin performs the way we expect it to, it outperforms the Uinta oil basin. So as we continue to gain confidence in that acreage position in the DJ, I think it's a normal shift for capital to leave Uinta and to move into DJ.

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

Okay, okay. And then can you talk about this most recent test on your eastern acreage? Was it on the northern block? Southern block? How far east was it?

R. Scot Woodall

It's on the northern block of the 2, and it is a fairly -- I guess it's like middle to east of that, if you're thinking about it from an east-west.

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

Okay, okay. And then finally, on these frontier tests, very solid rates here and was surprised that these were only 4,000-foot laterals. Can you discuss where those wells were on your acreage, whether they're operated or not, well cost, working interest, et cetera, there?

R. Scot Woodall

Sure. In terms of well cost, they're in that $7 million to $8 million type of a range. In terms of working interest, one of them is a 20% working interest, one of them is about a 30% working interest. And yes, we do operate both of those.

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

Okay, that's great. And then how much of your acreage in the PRB do you feel like is derisked for the frontier at this point?

R. Scot Woodall

Yes, those are just our first 2 frontier tests. Some of the activity by other operators have derisked some of it, but I'm not sure I could give you a percentage right now, I guess, Ryan. What we did in 2013 is we are drilling another 5 wells. Almost all of those have been focused on the Shannon, in an area that our confidence has risen up on quite a bit. And actually, our working interest is fairly high there. We have a working interest there on those Shannon wells of about 75%. So when we look at our acreage position in the Powder, we are targeting multiple horizons. And if you were to aggregate our entire acreage position, our working interest is kind of low, but we have pockets of it that range up fairly high, like in the Shannon area of 75%. So it really is kind of a mixed bag. But you're right, the initial well results are very positive and the initial rate of returns look very positive.

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

Right, absolutely. And then just one more, just finally, if I may. You mentioned kind of the Shannon area versus the Frontier area. Is there a geographic split that we can think about for that acreage, whether it's one of these zones is more on the north versus the south, in terms of just a working interest more so than the prospectivity of the acreage?

R. Scot Woodall

Not really. I think you have prospectiveness across the entire acreage for all of the horizons. We are probably the most excited about the frontier position that we have. However, all of these horizons do kind of overlap a little bit.

Operator

Your next question comes from the line of Jason Wangler with Wunderlich Securities.

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

Firstly, just on the DJ, as you bring in the third rig, I think you'd said before the first one is going to kind of do the pad drilling on the western portion and, obviously, the second is kind of on the eastern side. Are you going to kind of bring that third one in to the eastern side as well, or can you maybe just walk through the plan for all 3 rigs as we go throughout the year?

R. Scot Woodall

Sure, you're right. One rig will follow up on kind of the western portion of the acreage, following up on those 3 first 4-well pads that we did. The other couple of rigs will be in that eastern portion, and they will be doing a variety of things. They'll be doing some single well testing and delineation, and they will be doing some pad drilling there as well, both in the north portion of that eastern acreage and the southern portion of that eastern acreage.

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

Okay. And as far as -- and will, I guess, those 2 be doing the -- maybe the C wells and the Codells and maybe even the extended reach as well. Is that kind of the area you're focused on over there, is doing those tests, if you will?

R. Scot Woodall

Correct.

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

Okay. And there's been some talk lately about -- up in the Uinta and, obviously, the oil pricing not being great because of the constraints there. There's been some things I've seen on rail capacity, increasing income to the basin. Is there any commentary you guys have seen as far as trying to get a better price for the oil up there?

R. Scot Woodall

Obviously, we have been working on lots of options in that basin for a long time. And I think you're starting to see pieces of that come to fruition. We also see where there's more and more being railed out of basin. I think all of that helps the overall pricing for everybody in the basin. So we're excited about the opportunity and really are excited about where pricing may go in the future.

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

Sure. And Bob, just one quick one for you with the numbers, and thanks for the breakdown and the kind of pulling out the G&A and things. Do the guidance numbers include the onetime expenses, or should we be pulling those out when we look at the full year guidance?

Robert W. Howard

All the guidance numbers that we have reflect the results for the first quarter, so include the onetime numbers.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to talk about the trajectory of oil production guidance in part given the comments that you're focusing a bit more on pads in the DJ Basin. Can you just talk about how we should expect the trajectory of oil growth within the context of the 50% to 55% guidance for the year?

R. Scot Woodall

As I said, it's more back loaded. I think you'll see more of the ramp start to happen in, say, the middle of the third quarter and into the fourth quarter would be the way that we have it modeled.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got it. And I guess, to get to the midpoint of that would imply about 1,700 barrels a day or so of growth per quarter. So do you feel you'd be in a position, if you're not growing at that rate in the second quarter, to grow at a meaningfully greater rate in the third and the fourth quarter? It's just based on the timing of when you expect these pads to come on.

R. Scot Woodall

Yes, we really don't speak to production and growth quarterly, Brian. But we still believe that we're on track for those targets. And like I say, it's just going to be a little back-end weighted.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then following up on the pervious question with regards to the rigs that you have testing the east and the southeast, at what point would you expect to test the edges, the eastern and southeastern edges of your acreage? Is that something that you would expect towards the end of the year or before, or should we -- just we expect that -- those single rigs of -- single well rigs will be just pushing a little bit further east and a little bit further south gradually as we go through the rest of the year?

R. Scot Woodall

It's somewhat gradually, but there's a number of tests that are moving pretty far to the east and pretty far to the south planned for this year. But it is kind of a gradual step out.

Operator

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

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

Just back -- and maybe I've missed this in the past, but Bob mentioned West Tavaputs gas as a potential sale candidate. I know you guys have said everything is on the table except for Uinta and DJ. Can you talk about West Tavaputs gas specifically versus the Piceance gas transaction or what -- how we should think about -- how you guys are thinking about the divestment process?

R. Scot Woodall

What we said, David, I think we're looking at multiple things that we would consider selling. I think West Tav is definitely one. We have a fairly good benchmark on the Piceance, I mean, with the transaction that we did in the fourth quarter. And so we kind of know what we think the market would probably give us for that. And we think that we need to test the market on a number of our assets and then make the right business decision for the company.

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

Okay. And when I think about the cash flow impact of the company, obviously, Piceance, you're not spending any capital, which can cash flow. So is it fair to say that the West Tavaput sale would be less -- just looking at that particular metric, that would be less detrimental? I know you probably don't like that word, but less impactful to 2013 cash flow and CapEx versus -- the funding gap is where I'm going with that. Does that question make sense at all?

R. Scot Woodall

Yes, I think I get where you're going a little bit. One, we're also not spending any CapEx in West Tav, so it would be a CapEx-neutral event. I think you're right that West Tavaputs, probably, cash flows less than Piceance does.

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

Okay, all right. In the Powder, I know a lot of this acreage is -- you have working interest and et cetera. Do the operators have a pref right if you were to have -- if this were to be sold?

R. Scot Woodall

No. We don't think that anybody has a pref right on any of that acreage.

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

Okay. And of the 67,000, how much of that is operated?

R. Scot Woodall

Well, I'm looking around the room here, David, and nobody is immediately giving me an answer.

Robert W. Howard

70% to 80%.

R. Scot Woodall

Yes, I guess they're saying 70% to 80%, we think, we operate of that net acreage position.

Operator

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

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

I just wanted to get some color on 2 items. Number one, what are your thoughts about West Tavaputs and the Piceance in a higher gas price environment, not necessarily just for this year, but as you think '14 and beyond, especially as the gas market demand improves, et cetera? And it's a good asset for you guys and should be a good cash flow asset. And then secondly is just a little bit of color on the divestiture market. You mentioned sort of second half of the year. Do you feel like it's a pretty active market right now and you feel pretty confident in your ability to execute on that?

R. Scot Woodall

Sure. First, going to the first part of your question of Piceance and West Tavaputs. You're right, we think they are great assets. And you think back a few years ago, those were the bread-and-butter assets of the entire company. And so the reason to think about selling some or all or do some sort of monetization of those 2 assets is not because we don't like those assets, it's really is about redeploying the capital into what we believe are stronger rate-of-return assets in the DJ Basin and in the Uinta. Clearly, future gas price, as you know, fall into your decision-making about whether or not you monetize those or don't monetize those. So I think once we get down the path of opening data rooms and seeing what prices the market bears for those assets, we'll have some business decisions that we'll have to huddle around the table and make. In terms of our assessment of the overall M&A market, we've had an awful lot of interest in a number of these assets. So we feel fairly confident that we will be able to execute something in the second or third quarter here, or at least we're going to get started in the second quarter. I guess it's probably more of a third, fourth quarter of actually getting something executed. But we have been kind of soft marketing a number of our assets, have an awful lot of interest. And so it is definitely something that we think that we will be able to conclude this year.

Operator

[Operator Instructions] Your next question comes from the line of Jeff Robertson with Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

Scot, a question for you on the Niobrara C and the Codell, and maybe if you'll comment on the A. But it looks like, on the cartoon you all have used in the past, the C thickens a little bit on the eastern 2 blocks of your acreage position. I'm just curious how much you actually know about their reservoir quality or the reservoir properties on the C on that part of that acreage from either work you all have done and what you've seen others do?

R. Scot Woodall

Sure. I guess we are -- think that as you go on the eastern portion of the acreage, in that southern half is really where we're the most interested in the C. And the C thickness actually becomes equal to the B or, in places, even greater than the B. And so we're really pretty excited about the C more on the southern half. And I think you'll see more of our testing that we're going to do in 2013 will be on that southern half, where we did the C test.

Jeffrey W. Robertson - Barclays Capital, Research Division

Does that area have much production from the Niobrara C vertical wells that you can tie into?

R. Scot Woodall

No, it really doesn't. There's some vertical penetrations there and it's also where we're getting some of our data points from, but there is very little production down there.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay. And then on the Codell, it also looks like it thickens, at least maybe on the southern part of your acreage on the east. Is that where you test the Codell there, as well?

R. Scot Woodall

Yes, the Codell tests that we're thinking are probably more on the western portion of the acreage. And I think there's some more to the north, but that is definitely one that we need to gather more data on, and so that will be a very methodical step out type of a process.

Jeffrey W. Robertson - Barclays Capital, Research Division

When would you expect to have any kind of drilling results? Is that -- would you get that by the third quarter, or will that be something at the end of the year or early next year, to have enough history with those tests that we'll just talk much about them?

R. Scot Woodall

Probably later in the year, I would guess, Jeff. I don't have the exact drilling schedule sitting here, but our engineers always like more time. So I'll defer and say later in the year.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay. And then lastly, other than looking at the A on logs, will you do anything with that zone this year?

R. Scot Woodall

I don't think we have any plans to test the A in 2013.

Operator

Your next question comes from the line of Mike Schmitz with Ladenburg.

Michael Schmitz - Ladenburg Thalmann & Co. Inc., Research Division

Yes, one other question on the asset monetizations. You highlighted the PRB in the West Tavaputs. I mean, is your thought is that you do monetizations in one asset this year, or do you think you might need to do more than one monetization to meet the funding gap?

R. Scot Woodall

We're still just looking at the funding gap, and that's the target. Whether that takes one transaction or multiple transactions, I guess, we'll have to wait and see. It's still just our thought that we needed to probably enter the market with multiple opportunities and then choose which one we think makes the most sense for the company versus doing them sequentially, and then if you didn't like the price you got for the first asset you put up for sale, then you're kind of starting to bump up against our deadline towards the end of the year. So that's why we're going to enter the market on multiple fronts here shortly.

Operator

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

I was hoping you could just talk about general activity levels or the industry activity levels you're seeing in the Powder River Basin and the interest up there. Earlier this weekend, SM come out, peg at 1 million BOE-type curve on their Frontier prospect up there. Chesapeake has 10 of their 80-some rigs working in the Powder. Have you seen a noticeable uptick there recently?

R. Scot Woodall

Yes, absolutely. It has definitely has been a very hot play. I think it has kind of flown underneath the radar screen a little bit the last couple of years because probably the private E&P sectors were leading that charge in earlier years. You're seeing some more of the publicly traded companies jump in recently that I think it's kind of just elevating the whole industry awareness of it. But it's been active for several years. We put our position together quite a while back. It definitely is gaining a lot of momentum.

Michael Kelly - Global Hunter Securities, LLC, Research Division

You've got scale there, and I'm just curious to how you kind of balance the, well, I guess, the trade-offs and the opportunity of keeping it versus monetizing it. And whether you see this as it's just too early to tell and the focus is on the balance sheet at this point and you'd want to monetize it, or could this possibly be really the third leg on the oil prospect side here within the next couple of years?

R. Scot Woodall

You're probably seeing all that right, Mike, in that some of those tough decisions as we sit around and talk about it. Because we like the well -- individual well economics. We're not sure if we have enough scale or if we can get more scale, so that's some of the questions we ask ourselves. When you look at selling an asset, this is one that has very little cash flow and very little production now. Probably you could get a pretty good price for it, so in terms of impact to borrowing base and the impact to this year's cash flow. That is a plus. But it could become that third leg of the stool, like you said too. So that's all the balance that we're going to have to do over the next few months.

Operator

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

Dan McSpirit - BMO Capital Markets U.S.

Can you speak to maintaining debt levels? I know that question has been asked several times already, but can you quantify how much is needed from asset sales to cover the gap to not increase leverage this year by your model? That's my somewhat indirect way of asking what you estimate to be the funding gap this year.

R. Scot Woodall

And Jennifer starts frowning at me, telling me that I can't give cash flow guidance or something, but if you read all the same reports that I read, you're probably somewhere in that $150 million, $200 million type of a range that we're looking to plug a funding gap of.

Dan McSpirit - BMO Capital Markets U.S.

Okay, got it. I appreciate that. And as a follow-up here, recognizing it's still very early innings. Can you quantify how much of the Northeast Wattenberg leasehold is prospective today for the A and C benches, as well as the Codell?

R. Scot Woodall

I don't know if I have a breakout. Like I say, we're not as thrilled with the A, so we're not really focused on the A. I'd be guessing if I told you about the Codell and the C. I think we've got to put a few penetrations in the ground and kind of get some data first.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And as a follow-up to that, can you speak to DD&C costs for the Niobrara B bench wells? What is that today, and maybe expectations on a development-drilling basis?

R. Scot Woodall

Sure. Kind of what we -- our actual results from last year, where we did the pad drilling, we probably averaged something in that $4 million to $4.2 million. And then on non-pad wells, we're up $300,000 or $400,000 from that number, so more like $4.5 million or so.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And I'm going to squeeze one more in here just for really modeling purposes. Can you speak to the product mix of Niobrara B bench wells, that is how much oil, NGLs and natural gas? Just kind of rough percentages, maybe?

R. Scot Woodall

Bob's pointing here to something. Go ahead, Bob.

Robert W. Howard

Yes. In our investor presentation, we have a split down between those products and our type oil curve, which is a -- basically an amalgamation of all of our activities for the year, that point to about 65% oil, 21% gas and 14% NGLs from the Northeast Wattenberg economics for the year. That's probably as good a starting point as any.

Operator

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

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

Just a quick follow-up, and I apologize if I missed this, but did you give the cut of the Frontier well, the Powder as far as the oil, NGL, gas stream?

R. Scot Woodall

No, we didn't, but it's high. It's like an 80%, 85% type of an oil number. I'm not sure about the NGLs.

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

Is the Sussex and Shannon the same? I mean, they're all the same target, they're all 70%, 75% and up oil?

R. Scot Woodall

I think that's correct. I think that's the way to think of it.

Operator

At this time, we have exhausted all questions in the queue. I would like to hand the presentation back over to Ms. Jennifer Martin for closing remarks.

Jennifer C. Martin

I would like to say thank you to everybody for joining us today, and always feel free to give us a call if you have any further follow-up questions. Thank you.

Operator

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now all disconnect, and have a great day.

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