May 7, 2015
Executives
Michael G. Edwards - Senior Director-Investor Relations Barton R.
Brookman, Jr. - President and Chief Executive Officer Gysle R.
Shellum - Chief Financial Officer Scott J. Reasoner - Senior Vice President-Operations Lance A.
Lauck - Senior Vice President-Corporate Development
Analysts
Brian Michael Corales - Scotia Capital (USA), Inc. Neal D.
Dingmann - Suntrust Robinson Humphrey, Inc. Jeffrey L.
Campbell - Tuohy Brothers Investment Research, Inc. Welles W.
Fitzpatrick - Johnson Rice & Co. LLC Jamil A.
Bhatti - Wells Fargo Securities LLC Michael S. Scialla - Stifel, Nicolaus & Co., Inc.
David E. Beard - IBERIA Capital Partners LLC Jeffrey R.
Connolly - CIS Capital Markets LLC Paul Grigel - Macquarie Capital (USA), Inc. Ben Wyatt - Stephens, Inc.
Operator
Greetings and welcome to the PDC Energy 2015 First Quarter Conference Call. At this time, all participants are in a listen-only mode.
A brief question-and-answer session will follow the formal presentation. As a reminder, this conference call is being recorded.
It is now my pleasure to introduce your host, Mr. Michael Edwards, Senior Director, Investor Relations.
Mr. Edwards, you may now begin.
Michael G. Edwards - Senior Director-Investor Relations
Thank you. Good morning, everyone, and welcome.
On the call today we have Bart Brookman, President and CEO; Gysle Shellum, CFO; Lance Lauck, Executive Vice President; and Scott Reasoner, Senior Vice President, Operations. We posted a slide presentation that accompanies our remarks today on the Investor Relations page of our website, pdce.com.
I'd also like to call your attention to our forward-looking statements on slide two of that presentation. We will present some non-GAAP financial numbers on the call today, so I'd also like to call your attention to the appendix slides and the reconciliation of non-GAAP financial measures.
With that, let's get started. I'll turn the call over to Bart Brookman.
Barton R. Brookman, Jr. - President and Chief Executive Officer
Thank you, Mike, and welcome, everybody. A very strong first quarter for the company and a great first step towards our 2015 corporate and operating goals.
While this commodity pricing environment continues to present challenges, we remain very encouraged by the company's operating results and financial strength. Several key points I hope you take from this call.
First, our production growth, a direct result of the ongoing drilling efficiencies and technical improvements in our operations. Second, the strength of our balance sheet, a result of the recent equity offering, and we also recently reaffirmed our bank line at $700 million.
Currently, the company maintains liquidity over $750 million. Last is our hedge program.
In the first quarter, we had hedging gains of approximately $50 million and the mark-to-market value of our hedges at quarter-end remained over $300 million. Let me cover some highlights from the quarter.
First, productions for the company, 2.9 million barrels of oil equivalent or 32,200 Boe per day. This is a 41% improvement from the first quarter of 2014, and very important, this is a 15% jump in daily production from the fourth quarter 2014 levels.
We're really, really pleased with the overall production levels of the company. This is a real credit to our operating teams in the Wattenberg Field and our Utica operations.
Oil production for the company was 14,500 barrels of oil per day. That is 45% of the production mix for the company right in line with our expectations.
We do expect the liquid mix for the company to increase slightly as we move through the balance of the year, but our liquid mix guidance for 2015 remains 45% oil, 20% natural gas liquids, and 35% natural gas. The cash flow from our operations, $74 million for the quarter, slightly above our expectations.
This is primarily due to the production performance. Let me touch on some of our operating results and Scott will give a lot more detail on this in a moment.
Again, we're very encouraged by the drilling efficiencies we're achieving with the five flex rigs currently running in the Wattenberg Field. These more efficient rigs continue to improve our drill times and overall cost structure for the company.
Our spud counts and turn in lines are slightly exceeding our expectations and our second quarter should be very strong with a record number of turn in lines for the company coupled with the expected Lucerne 2 plant start up for DCP. We anticipate significantly lower line pressures beginning in late June.
And then our balance sheet. Once again, we recently reaffirmed our $700 million bank line and on liquidity for the company is over $750 million.
We expect to be undrawn on our revolver year-end 2015 and our debt-to-EBITDAX ratio at year-end should be approximately 1.5. This gives us tremendous operational flexibility to accelerate if market conditions improve.
Those are the highlights. We'll fill in the details as we go through the presentation.
I will now turn the call over to Gysle for the financial overview.
Gysle R. Shellum - Chief Financial Officer
Thanks, Bart, and good morning, everyone. Thanks for joining us this morning.
As always my comments are high level, so for more complete analysis of our quarter, please see our press release and our 10-Q we filed a little earlier this morning. We had a good start to 2015, lots of activity in Wattenberg and completion of our 4-well Cole pad in Utica.
Production for the first quarter as Bart mentioned was 2.9 million barrels of oil equivalent or 32,162 barrels of oil equivalent per day. Our first quarter reflects the success of both programs with record crude oil production to PDC in the Wattenberg and a new high in Utica.
We had 20 turn in lines in the quarter, about 50% fewer than the fourth quarter 2014. Scott will have more on production for the quarter in a minute.
Despite much lower commodity prices, we still saw growth year-over-year from adjusted cash flow from operations and adjusted EBITDA, aided by our hedge position with $50.4 million in realized hedge gains in the first quarter. Finally, all our metrics for the quarter were on the high side of our internal estimates.
So we're really pleased with the outcome. Now let's talk about some of the metrics.
Although year-over-year production increased over 40%, our first quarter oil and gas sales were down 38% compared to the first quarter 2014. Oil and natural gas and NGL prices all declined quarter-over-quarter.
Crude oil prices, net of differentials for the first quarter 2015 averaged $39.82, down 54% from the first quarter of 2014. Average natural gas prices were down 46% from the first quarter 2014 and net NGLs were down 64%.
We factor in our realized hedges, however, sales plus hedges were up approximately 10% in the current quarter compared to the first quarter last year. The $50.4 million net realized hedge gains in the first quarter compares to net realized losses of $7.2 million in the first quarter of 2014 and a net gain of $19.2 million in the fourth quarter of 2014.
Production costs on a per unit measure were down about 5% year-over-year, production costs include lease operating expenses, production taxes, overheads and some transportation and processing costs in Utica. For the first quarter 2015, we averaged $8.35 per barrel of oil equivalent, down from $8.81 per BOE in the same quarter last year.
Scott will talk more about LOE in a few minutes. Gross margins were 67% of sales for the first quarter of 2015 compared to 85% for the first quarter of 2014, reflecting a substantial decrease in commodity prices and a slight increase in total production costs.
DD&A includes depreciation of fixed assets and depletion of oil and gas properties. The increase in the current quarter over the same quarter last year is due to the increase in production offset by a decrease in the overall DD&A rates in the two periods.
Per unit depletion rates on just oil and gas properties in the first quarter of this year was $18.92 per Boe compared to $20.45 per Boe in the first quarter of 2014. G&A decreased in the first quarter of 2015 compared to the first quarter last year largely due to the $3.3 million litigation charge last year.
G&A on a per Boe basis decreased 41%, $6.45 in the first quarter this year from $10.96 in the first quarter last year. To our non-GAAP financial data, adjusted net income in the first quarter was $7 million, a decrease of 27% compared to the same period 2014, a 41% increase in production drove DD&A higher during the quarter and that combined with lower commodity prices resulted in a drop in earnings quarter-over-quarter.
In spite of the decrease, we were near the high-end of our internal earnings estimate for the quarter. Adjusted cash flow from operations is defined as cash flow from operations, excluding charges – changes in working capital.
Adjusted cash flow for the first quarter this year was $74 million or $2 per diluted share compared to $69.7 million or $1.95 per diluted share in the first quarter last year. Adjusted EBITDA in the current quarter was $82 million, up slightly compared to the first quarter of 2014.
Adjusted EBITDA per diluted share of $2.22 was also up slightly in the current quarter compared to last year. Last week, our bankers reaffirmed as Bart mentioned our $700 million borrowing base and we elected to keep our commitment level at $450 million.
The table on page eight reflects PDC's borrowings. We began 2015 with $56 million drawn on our revolver and had $16 million in cash.
In March, we completed the equity offering of approximately 4 million shares with net proceeds of $203 million. We retired our debt on the revolver, and as of March 31, had cash on the balance sheet of $67 million with cash and over $700 million on our borrowing base net of a $12 million letter of credit, we have $756 million of liquidity at quarter-end.
Turning to our hedges, our hedge positions in place as of April 30 are shown on this page. The mark-to-market value of these hedges at March 31 as Bart mentioned was $315 million.
We have significant hedges in place for the balance of 2015. About 85% of our expected crude oil volumes are hedged at a weighted average price of $82 – $88.82 per barrel.
We have about 75% of our expected gas volumes protected at a weighted average floor at $3.74 per MMBtu. For 2016, 4.1 million barrels are hedged.
That's about 80% of our total hedge volumes we had for 2015 at a weighted average floor of $84.99 per barrel. About 30% more of our gas volumes are hedged in 2016 than we had this year at a weighted average price of $3.75 per MMBtu.
We also have good hedge volumes on natural gas for 2017 and have been considering adding more in the $3.40 range for both 2016 and 2017. A small slice on hedged oil in 2017 is in the low 60%s.
Very recently, we've seen opportunity to add some 2017 oil costless collars with ceilings in the mid 70%s and we think that could be an attractive trade for a small tranche of 2017 production. We're still bearish to get on gas through 2017 and we're gaining confidence on the bullish side for oil.
With that I'll turn it over to Scott for a discussion on operations.
Scott J. Reasoner - Senior Vice President-Operations
Thank you, Gysle, and good morning, everyone. We had a terrific first quarter and I'd like to thank our land, EHS and production teams for the great work they've done this quarter.
As noted, first quarter production was 2.9 million barrels of oil equivalent or approximately 32,200 barrels of oil equivalent per day. This is a 41% increase over 2014 levels from continuing operations and a 15% increase in the daily rate compared to the fourth quarter of 2014.
Our Wattenberg production increased 42% year-over-year and our Utica production increased 35% over the same period. Moving into a little more detail on our production results, volumes are trending slightly above our internal estimates, thanks to better performance from our capital program, continued outperformance from the Dynamite Pad in the Utica and better-than-expected non-operated production from recently turned on wells.
You can see here that our commodity breakdown included 45% oil in the first quarter. As anticipated, first quarter production had slightly higher gas content than our full year guidance due mainly to first quarter completions being focused near the inner core of the Wattenberg and non-operated production volumes being slightly above our expectations for the quarter.
As a reminder, our non-operated gas sales are predominantly paid on a wet gas basis and we don't include the NGL volumes. We expect the NGL percentage to increase slightly throughout the year – remainder of the year, but more importantly, are pleased with the growth in oil volumes we've seen this quarter and reiterate our 65% liquids full year guidance.
We experienced high line pressure in the Wattenberg throughout the quarter. We expect the Lucerne plant to be fully operational late in the second quarter, which we expect to greatly alleviate the line pressures that we've been seeing.
Our production teams have done a great job managing our legacy vertical wells that have been impacted by the – the most by this high line pressure. We expect these wells recover and produce at capacity in the third quarter once the Lucerne 2 plant comes online.
We're currently evaluating several factors including the benefit from it, the Lucerne 2 facility and our higher average working interest related to non-consents and how that will impact the remainder of the year. But as of now, we are trending to the high side of our production guidance of 13.5 million barrels of oil equivalent to14.5 million barrels of oil equivalent for 2015.
The associated daily production rates can be seen in the graph on the bottom left of the slide. In the Wattenberg, we have highlighted several of the key projects that we have planned for 2015.
The downspacing test, including the Chesnut in Section 28, which is testing downspacing with extended reach laterals reviewed in detail at our recent Analyst Day. As you can see, the project started flowing back just over a week ago and has started producing this week.
All gas and NGLs from these wells will flow through Aka Energy's facility, so these wells will not affect DCP system pressure. I would encourage you to revisit the Analyst Day slide for a look at the breakdown of Niobrara Bs, Niobrara Cs, and Codells of each of these projects.
As you can see from the map, the downspacing tests and extended reach laterals – lateral drilling in 2015 are spread throughout our Middle Core. We feel that the results of these technical projects will go a long way toward our continuing growth of knowledge of the true resource potential of our Wattenberg acreage.
A couple of other points to know in Wattenberg. Both the Niobraras and Codells on the SunMarke pad, which we also provided an update on at Analyst Day, continue to track at our updated 440,000 barrel Middle Core type curve.
We're testing plug-n-perf completion design and have been encouraged by these results to-date. Though it is very early, wells completed utilizing this method are seeing 25% to 35% increases in production rates compared to our standard method with only a 6% increase in associated costs.
We have approximately 30 plug-n-perf wells scheduled for this year, and as a reminder, any uptick in the production associated with this method was not included in our full year guidance. We also are currently testing AccessFrac, which is a process that includes BioVert diversion material.
The data that I showed at Analyst Day was very encouraging. And again, I want to say it's early, but please revisit our Analyst Day slides for more detail.
Now, moving to the Utica, as we discussed on the year-end call, our Dynamite Pad has been showing strong results through the first 100 days of production tracking above our 680,000 barrel of oil equivalent type curve. Our 4-well Cole pad is expected to come online within the next week and utilize the similar completion design as was used on the Dynamite Pad.
While it will be several months before we can speak to results from the Cole wells, the drilling and completion ran very smooth and we are very excited to see how they come in from a production standpoint. In the Utica, we are currently estimating completion – completed well cost to come in around $7.5 million to $8 million for a 6,000 foot lateral.
Next we'll go through our turned in line and spud activity in the first quarter and give a little color on what to expect in the second quarter. As you can see, we spud 34 operated wells and turned in line 20 operated wells in the Wattenberg in the first quarter.
There were 11 non-operated wells spud and 11 wells turned in line in the quarter with an average working interest of approximately 22%. Doing some quick math, you can see that we are a little ahead of schedule in terms of our operated wells spud compared to the 119 we've guided to.
On the non-op front, there are several moving pieces involved. Although first quarter wells spud was in line with our original expectation, we are anticipating a decline from our original projections for the full year as we see our peer companies' drilling pace slow.
However, as I mentioned earlier, these wells are currently exceeding our production expectation. Due to a number of non-consents, we have a higher working interest in our operated wells than we originally projected.
Because they are from this year's drilling program, the added interests are in our middle and inner core areas with very favorable economics. We're currently paying close attention to these moving factors and will provide more color as its available.
For the second quarter, we are expecting to turn in line nearly 50 wells. We expect between 40 and 45 of those wells to be in the Wattenberg with 34 of those being extended reach laterals.
As a reminder, the first few of the 10 well Chesnut pad is being brought online, and we don't expect any delays with the remainder of these wells. Moving onto the capital program, you can see that we spend a $140 million in the first quarter, $120 of which was in Wattenberg.
More efficient operations as well as higher working interest in our wells due to peer non-consents has led CapEx to be slightly higher than internal estimates. Over the course of the first quarter, drilling costs per well migrated lower and currently sit at approximately $3.4 million for a standard lateral and $4.4 million for an extended reach lateral.
As with the turn in lines and well spud, we continue to pay close attention to this trend and will provide an update if needed when appropriate. In the Utica, we spent $18 million in the first quarter primarily on the completion of the 4-well pad, and much of the remainder of the Utica budget has been spent in the early part of the second quarter to finish the completion and equipping for this pad.
There are still dollars allocated for some leasehold and land work to prepare us to return to drilling when the time is right. Our lease operating expense for the quarter was approximately $5.46 per BOE.
With continually increasing volumes and high line pressure built into our projections early in the year, we expected our LOE per BOE to be higher than the guided range in the first quarter. I will note that there was an accrual of an estimated $3 million of environmental remediation projects planned this year that inflated our LOE for the quarter.
We do not anticipate these charges to be recurring. As our production continues to grow in future quarters and the costs associated with high line pressure start to come down, we fully expect our LOE rate to decline accordingly.
In addition, we have seen high water disposal – high water disposal trucking costs that are expected to come down as wait time has reduced. This is expected as our third-party disposal company capacity increases later this year.
Finally, you can see a recap of the main points that I just covered. We're very pleased with the way our team has performed in the first quarter and our second quarter is already off to a good start.
With that, I'll turn the call over to the operator to begin Q&A.
Operator
Thank you. Our first question comes from Brian Corales from Howard Weil.
Your line is open. Please go ahead.
Brian Michael Corales - Scotia Capital (USA), Inc.
Hey, guys. Just one on the cost side, I think in the Wattenberg, $3.4 million, does that – is that a plug-n-perf well?
Are those plug-n-perf wells, extended lateral plug-n-perf?
Scott J. Reasoner - Senior Vice President-Operations
No, they are not. They are – they are the sliding sleeve process that we use for completion, which is our standard completion method even as of today.
Brian Michael Corales - Scotia Capital (USA), Inc.
Can you – how much more is a plug-n-perf?
Scott J. Reasoner - Senior Vice President-Operations
It's roughly 6%.
Brian Michael Corales - Scotia Capital (USA), Inc.
Okay. And any early – the Chesnut well pad, is it early flow back – I mean how does that look at – I know it's early days?
Scott J. Reasoner - Senior Vice President-Operations
We really just got started turning those wells online last week. And so we're really seeing early data as many as few as a day or two at this point.
But I don't expect those wells to be anything other than on our type curve. I mean, we're looking at wells that are right in the center of our Middle Core.
We should be seeing very predictable results there.
Brian Michael Corales - Scotia Capital (USA), Inc.
And then just one final question, you talked about the higher working interest in the Wattenberg and maybe CapEx trending a little bit higher. Can you maybe quantify that or if this maintains, I mean – my guess is production will likely move higher as well.
Can you maybe quantify how much higher on the CapEx side and maybe how much higher on the production side you could be?
Scott J. Reasoner - Senior Vice President-Operations
Sure, I'll do what I can with that. From a CapEx perspective, our costs are still moving downward as we even work through this today, we're continuing to negotiate with our service providers and discuss with them.
That's a factor that we're still looking at. Our drill pace continues to increase and we're not sure where that's going to land yet, but we're expecting over the next couple of months to better understand that.
Our non-operated pace, we still think that's going to tail off. And so we're looking at how that's going to impact us through the year.
And then the non-consent pace, we've seen a substantial number of non-consents in the first quarter, but we expect that to taper down through the year as companies figure out alternatives to going non-consent. So, from a CapEx impact, we're really looking at all those factors and they really aren't ready to make a decision on where these numbers are moving at this point.
When you move to the production side, we're talking about many of the same factors affecting us. The non-ops position, the DCP Lucerne coming up and really seeing it run efficiently and effectively is something that we're dependent on in the second half of the year.
And the non-consents as well could impact our production, and then finally, that drill pace as well. I mean all those factors kind of go hand in hand on both sides, but for the same reasons, we're really not ready to change our production estimates at this point as well.
Brian Michael Corales - Scotia Capital (USA), Inc.
Scott. That was very helpful.
Thank you.
Scott J. Reasoner - Senior Vice President-Operations
You bet.
Operator
Thank you. Our next question comes from Neal Dingmann from SunTrust.
Your line is open. Please go ahead.
Neal D. Dingmann - Suntrust Robinson Humphrey, Inc.
Good morning, guys.
Scott J. Reasoner - Senior Vice President-Operations
Hi, Neal.
Neal D. Dingmann - Suntrust Robinson Humphrey, Inc.
So I'm just looking at this slide I forget if it's the current deck or I think it's maybe the prior one from IPAA. Your expectations on the downspacing, just your thoughts on – I see where the 26 wells per section on the Rieder, and I'm just wondering – now when I look at that on parts of your other core area, how optimistic are you that, that will continue throughout that, not just in the Rieder, but as you expand that, I guess, a bit north if you would?
Scott J. Reasoner - Senior Vice President-Operations
Yeah. I can give you a little – I think I can give you a little bit of insight where we stand on it.
I think when you look at the SunMarke pad and the success we've had there, you can correlate that to what we say is everything is running smooth on that. So we've decided based on that to move forward with these next projects.
And again with the amount of rock that we have, that we're working with, it being 300 feet to 350 feet of rock there dependent on where you're in the field. We have a lot of potential here.
And really we look at these steps, these increments that we're making is very – our chances of success – we wouldn't take them on if the chance of success wasn't fairly high. And I think that's probably the best way for us when we start to look at this to describe it to you as I guess along those lines.
We're continuing to move forward and I hope everybody realizes we haven't spud the first Rieder well yet. It's really slated, I think, in the next month or so to begin the drilling on that particular pad.
So we really won't see Rieder results 'til really probably second quarter of next year with the drilling of that entire pad to get done.
Neal D. Dingmann - Suntrust Robinson Humphrey, Inc.
All right. Thank you.
Operator
Thank you. Our next question comes from Jeffrey Campbell from Tuohy Brothers Investment.
Your line is open. Please go ahead.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Good morning.
Scott J. Reasoner - Senior Vice President-Operations
Good morning, Jeff.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
First thing I want to ask you is about the Dynamite Pad production outperformance. Can you add any color surrounding any of the specific completion innovations that you performed on that pad and how those results are looking today?
Scott J. Reasoner - Senior Vice President-Operations
Yeah. The Dynamite continues to I think surprise us.
We're very pleased with the results that we see there. The teams have worked hard to improve on the completions methods.
We've done some pinpoint fracturing on some of the wells, done some sliding sleeves that are cemented in on several of the wells. We haven't done a full well bore out there with sliding sleeves that are cemented in yet, but we're continuing to test that concept.
We like the results we see from obviously with the 15% over our type curve type numbers. But we are still very early and we're going to be watching that very well, very carefully as we continue – as we see the first production from the Cole as well.
And we did use similar completion methods on the Cole pad hoping that we can repeat that 15% type improvement.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Sort of following on that idea of production improvement. In the last quarter, you said you needed $70 a barrel to $80 a barrel to get excited about the Utica again.
If this production enhancement that we're seeing at Dynamite holds up and continues with Cole, could that activity resume closer to $70 a barrel end of the range?
Barton R. Brookman, Jr. - President and Chief Executive Officer
Yeah. Jeff, this is Bart.
And I think our perspective on that is from the last quarter it probably has moved slightly. The results from these completions on the Dynamite coupled with the cost structure in the field.
And three months ago, we were probably in a state of mind of looking at the Utica cost and recognizing we had a $9.5 million per well cost structure and we're hoping I think at the time to get that in the low-$8 millions. I think our operating team now is pretty confident they're probably in that mid-$7 millions.
We're obviously not drilling, so it's more difficult. You're going off estimates versus actuals when you're actually drilling.
So the cost reduction coupled with our completion success are two of the things now that I think we've been out saying, we would like oil in that mid-$60s, maybe high-$60s when we really start looking at this and saying it begins to compete with the Middle Core area of the Wattenberg field.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay. That was very helpful.
And let me just ask one final question. It sounds like Lucerne performance is built into your current performance guidance, if I'm wrong, you'll correct me.
Can you provide some color as to the sensitivities involved here? For example, are there predictable downtime ranges for when new facilities start up that sort of thing?
Scott J. Reasoner - Senior Vice President-Operations
This is Scott. I can give you a shot at that and then Lance may add some more to this.
We're – the early time, we're expecting that facility actually to come on earlier than July, which is when we, in our budget, where we have it slated to actually start performing. And I think when you look at the discussion we had with DCP just recently, they're on schedule.
We're expecting that facility to run in mid-May and obviously there will be some bugs to work out. We're looking at that.
I would believe that in July unless they have something major that comes up, which generally they don't, but they'll be running reasonably smooth. There'll still probably be a few days here and there of downtime associated with that, but very manageable in terms of if it's not weeks, if it's just days, we can deal with as we have been the facilities that are out there.
So there's a lot more room to move once that additional facility comes on and these others still remain operational.
Lance A. Lauck - Senior Vice President-Corporate Development
And so, Jeff, sort of how we look at this from a production standpoint. Third quarter is where we look to see the benefit of the Lucerne 2 plant.
So although, it's going to mechanically start up sometime in May and it's going to be fully running from their perspective in June, we don't anticipate the benefits of that as we look at production for the year until July.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay. Great.
That was great color. Thanks very much.
Operator
Thank you. Our next question comes from Welles Fitzpatrick from Johnson Rice.
Your line is open. Please go ahead.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Hey, good morning.
Scott J. Reasoner - Senior Vice President-Operations
Hi, Welles.
Barton R. Brookman, Jr. - President and Chief Executive Officer
Hi, Welles.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
I appreciate the positive commentary on new completion techniques in the Wattenberg in the prepared comments. But specifically on the BioVert with 30 additional days of production, can you say is that still looking to be kind of 10% to 20% ahead of the standard sliding sleeve completion that you comped it against in the Analyst Day?
Scott J. Reasoner - Senior Vice President-Operations
Welles, this is Scott. And, yes, there is – I think we're still holding firm on that.
In fact, we're continuing to consider and actually have done some more BioVert wells in the second quarter as we completed all – a number of the wells that we're already working on. So we see the benefits of it still at this point, but we do have a very a few wells in that sample set.
So we're trying to spread that across to field more, so we understand how it impacts the greater area, make sure it isn't a one-time occurrence where we get a few wells that outperform just because of statistics, that type of thing is really where we're headed right now, and no different than the plug-n-perf methods. We'll continue to watch the production very carefully, continue to make decisions on moving forward particularly with the BioVert AccessFrac process.
We can make that change a few days before we actually frac the well because you don't have to wait – make wellbore changes whereas in the plug-n-perf method, we have to make that decision when we run the casing out.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
That's great. And am I remembering correctly that it's something in the $50,000 to $100,000 range per well for the BioVert?
Scott J. Reasoner - Senior Vice President-Operations
That's correct.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
Okay, great. And then one more kind of higher level question.
Obviously, commodity prices are running somewhere between the base case and the upside case scenario. Can you give us any insight as to you-all's thoughts around 2016 and what you-all's rig count might be?
Lance A. Lauck - Senior Vice President-Corporate Development
Welles, this is Lance. First of all, we're very encouraged that the oil prices for the fourth of 2015 has gotten to that low-$60s type of range and we're watching that and monitoring that, and that was sort of in the range of our expectations.
And then as you look into 2016, we're seeing more that's in sort of the mid-$60s type of range for oil price. And I mean to your point, I mean, that clearly exceeded some of the price forecast that we've had in our base case projections at Analyst Day when we looked at our outlook over the next three years.
So it's still early. We want to see how the oil prices ultimately shake out here as we go through more of 2015.
But, yeah, we're encouraged that the increased oil prices will definitely benefit and give us the strong look at increasing our rig pace next year. Until we get through our budgeting process where we get through towards the end of the year and make that determination, we don't know the specific rig counts yet for 2016.
But what we can say is we're encouraged by the prices that we're seeing thus far. And with that, we would consider the net – the rig pace consistent with what we're looking at in our base case.
But again, we've got to get down through the end of the year and finalize the numbers and see what the oil prices do.
Barton R. Brookman, Jr. - President and Chief Executive Officer
Well, this is Bart. This is Bart.
Just a little to add on this. Intuitively, I think we're looking at this right now, and when we're looking at the overall general results with the – now a six handle on oil price and hopefully additional rebound as we go through the year.
When you couple that with the production results, the drilling efficiencies that Scott talked about, some of these completion techniques that are adding to our drilling F&D. Scott, noted we continue to push even since Analyst Day on the cost structure, we're evaluating all of that.
And then we have this line pressure scenario as we go through the summer that's going to improve. We believe the line pressure is going to give us a lot of operational flexibility in the Wattenberg.
I mean, this is a 40% improvement on DCP's capacity. You take that improvement with decreased rig counts in the basin and we think we're going to have some good running room, line pressure going into 2016.
So I look at this and say, all of what Lance talked about are modeling and the very positive results we have. And then you take our balance sheet and look at the strength of it, we're going to have a lot of flexibility to potentially accelerate.
But as Lance said, that really, first thing we're going to do as a company is evaluate all of this data, come back hopefully next quarter, give full updates on the production and capital structure, all of that, evaluate and then roll right into that budgeting process. But I feel very encouraged overall about it right now.
Welles W. Fitzpatrick - Johnson Rice & Co. LLC
That's great. Thanks and congrats on the continued strong well results.
Operator
Thank you. Our next question comes from Mike Scialla from Stifel.
Your line is open. Please go ahead.
Barton R. Brookman, Jr. - President and Chief Executive Officer
Good morning, Mike.
Operator
If you have your phone on mute, can you unmute your phone please. Our next question comes from Jamil Bhatti from Wells Fargo.
Your line is open. Please go ahead.
Jamil A. Bhatti - Wells Fargo Securities LLC
Good morning, guys. Just real quick question.
Looking at the Churchill and Chesnut timing in the slide deck, I know at the Analyst Day, you kind of pointed to late April or early May timeframe. Does that shift a little tiny bit or is that just kind of breaking out Chesnut into the two separate parts?
Just want to see what was baked into the guidance versus the timing that's put in there now?
Scott J. Reasoner - Senior Vice President-Operations
We're really – I think it was really – we might be a week behind the schedule in our total plan there, but nothing more than that. When we start looking at bringing those wells online, we really started what would have been late April on the flow back.
It did roll in, obviously, rolled into May and the significant volumes will start coming online here over the next several weeks. So we might be behind a week, but with the significant number of projects as we've had, I don't think that's too bad with where we sit today.
Lance A. Lauck - Senior Vice President-Corporate Development
Jamil, the only thing that I would add to that is, all 34 of the Chesnut and Churchill wells are going to be go into Aka Energy, which is another third-party processor for us that we have in the field. And so those wells won't be going on to the DCP system.
So we're very thankful for that opportunity to bring those wells onto a different system other than that of the current timeline pressures that we're seeing on the DCP side.
Jamil A. Bhatti - Wells Fargo Securities LLC
Thanks for the color guys. That's all I had.
Thanks.
Operator
Thank you. Our next question comes from Mike Scialla from Stifel.
Your line is open. Please go ahead.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc.
Yeah. Sorry about that.
I wanted to ask on the LOE costs little bit higher than, I guess, we were expecting, Scott, you had mentioned that some of that was from – some accruals from some environmental costs and then high line pressures. I guess, one, trying to understand how the high line pressures impact LOE?
Is that just lower volumes to spread the fix component of LOE over, and then what's a good run rate for the remainder of the year?
Scott J. Reasoner - Senior Vice President-Operations
As far as the question on how does the high line pressure contribute? Really, both sides of the equation, Mike, if you look at the volumes and obviously, we've seen very high line pressures here recently, that's affecting our volumes.
But the cost side comes into that as well as we spend money on compression, swabbing and personnel to try to stay ahead of these wells. So really those three things probably are the primary factors to the cost equation.
In terms of run rate, we've talked about that somewhat and we look at this point like we'll be at the high end of our guidance, I'd say, is probably the best way to quantify it at this point. And we are very hopeful that our projections going forward are accurate that we – and we believe that to be the case.
I think we'll see – we'll see some real breaks in costs as we get through this transition from high line pressure to lower line pressure. It may take a little bit of time because you do have to – some of those wells, it will take a little work to get them recover back to their original capacity.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc.
Okay. And then you had mentioned that you plan to do 30 wells with plug-n-perf in Wattenberg this year.
It looks like those wells are doing extremely well. I think you continue to see that kind of outperformance, any ability to increase that number of plug-n-perfs this year?
Scott J. Reasoner - Senior Vice President-Operations
The answer is yes. The – as I've said, the main thing – the point that we need to make the decision on whether to go to plug-n-perf on completion on those wells is when we're running casing in.
So as we progress through the year, if we already have casing in the hole, obviously, if we have the sleeves in there, we can't go to a plug-n-perf, we have to run that casing, and without all that equipment on it, cemented in – and then we can do the plug-n-perf method. So there is a possibility that will increase, at this point, we think we've got a good plan – a good series of test we're going to do.
And I always point this out, because I don't want people to get overzealous with the performance we're excited about it, but it is very early and from a few wells.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc.
Okay. And then any plans to try that cemented sleeve technology this year in Wattenberg?
Scott J. Reasoner - Senior Vice President-Operations
We've talked about it a little bit, we've considered it and we've really haven't gone to that in yet. I think our Utica team is doing a good job and we're very surprised at how well they've gone.
There are – when you start putting cement behind pipe and sliding sleeves and that whole process caused me great concern, but our Ohio team has done a great job managing that. I think we'll be looking at that in the – on the Wattenberg side here in the next several months.
I mean, really we can get the same effect from a plug-n-perf. So those complexities that you could add by adding the sliding sleeves are not something we're quite ready for yet.
We'd love to prove up the concept first to the plug-n-perfs, but it adds – it adds some interesting – some interesting dynamic, because it can speed up the frac phase as you go to sleeves over the plug-n-perf process, which obviously...
Michael S. Scialla - Stifel, Nicolaus & Co., Inc.
Okay.
Scott J. Reasoner - Senior Vice President-Operations
... would impact cost, so.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc.
Right. And then last one for me.
You addressed this, I guess, I think in answering Brian's question, but just want to follow-up a little bit on – in terms of the production guidance you're guiding for the first quarter, pretty flat production and you obviously beat that by a pretty wide margin, up 15% from fourth quarter. Looking forward, you mentioned there is a whole bunch of moving parts there.
Is there any one particular thing that you need to see before you would consider – I know you said you're leaning toward the high end of the range, but before you'd bump up that whole range, well, is there something that you need to see before you do that?
Scott J. Reasoner - Senior Vice President-Operations
I think there is a couple of things that we obviously like to see. And probably the number one thing at this point is DCP bringing Lucerne 2 up and see the impact from it.
It's a critical piece of our puzzle for the rest of this year and particularly the second half where we have our volumes increasing substantially over – second quarter is really a function of -the increase that we're expecting in second quarter is a function of these Chesnut and Churchill wells coming online. Third quarter has – a full quarter of those wells being online with DCP.
And so, at this point, with the idea that we're well on our way to getting all those frac jobs executed in that Chesnut and Churchill area, we're – I'll put that one in second place behind the DCP, the project there with Lucerne.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc.
That's helpful. Thanks, Scott.
Operator
Thank you. Our next question comes from David Beard from Iberia.
Your line is open. Please go ahead.
David E. Beard - IBERIA Capital Partners LLC
Good morning, gentlemen.
Scott J. Reasoner - Senior Vice President-Operations
Good morning.
Lance A. Lauck - Senior Vice President-Corporate Development
Good morning.
Barton R. Brookman, Jr. - President and Chief Executive Officer
Good morning, David.
David E. Beard - IBERIA Capital Partners LLC
Just a clarification on your capital expenditures from the Q and the press release, the $140 million to the $167 million. Is that difference all carryover expense and do you have any more going forward?
Barton R. Brookman, Jr. - President and Chief Executive Officer
We're looking – David...
Gysle R. Shellum - Chief Financial Officer
I'm sorry, David. The $167 million is, where you get...
David E. Beard - IBERIA Capital Partners LLC
That was just from the Q and just the press release said $140 million. We can take that offline if you want to; it's just really a clarification?
Gysle R. Shellum - Chief Financial Officer
Yeah. I see it now.
I think if you look at the statement of cash flows, it shows CapEx of $176 million and down at the bottom, it's got $35 million, roughly $36 million of changes in accounts payable. So you net those two out, you get down to the $140 million.
David E. Beard - IBERIA Capital Partners LLC
Okay, okay. And then bigger picture question related to hedging, can you just talk a little bit about your philosophy here in terms of where you want to be hedged given where prices are and maybe look at either time or price relative to layering your hedges for 2016 and 2017?
Gysle R. Shellum - Chief Financial Officer
Yeah, David. This is Gysle again.
I mentioned in my comments that we're seeing some costless collars with ceilings for oil in the mid-$70s. And given our view of oil and that's both for 2016 and 2017, given our view for oil, which we believe the curve right now is a little bit weak in those years.
We lean toward a costless collar rather than a swap in those years. The swaps are in the low to mid $60s still.
The downside protection on that costless collar is somewhere in the $50s. And you go back to our Analyst Day presentation, our resilient case was at a $50 price where we still can grow.
We maintain a 5 rig pace and not increase rigs, but we still can grow 2016 to 2017 at that price. So that collar kind of make sense to us, we get a little bit more on the downside than our resilient case, and we can grab some of that upside.
The flipside of that on natural gas is we're – we're more bearish on gas prices in 2016 and 2017. We can snag a swap right now in the mid-$3s.
And we also hedge bases on CIG along with that, maybe not one-for-one, but we cover the bases as well. And at that price, we think opposite of crude oil that natural gas is not going to get to those levels in those years.
So we'd be more inclined to do a swap on gas in 2016 and 2017. It's important to remind everyone that we don't – we don't hedge everything all at once.
This would be another small slice of what we see for 2016 and 2017 in our forecast, I don't think, on only one occasion, we've hedged more than 10% of what we expect to happen in a year. So it would be that number or less, if we did pull the trigger on anything.
David E. Beard - IBERIA Capital Partners LLC
Okay, no, that's very helpful. I appreciate the time.
Thanks.
Gysle R. Shellum - Chief Financial Officer
You bet.
Operator
Thank you. And our next question comes from Jeffrey Connolly from Clarkson Capital.
Your line is open. Please go ahead.
Jeffrey R. Connolly - CIS Capital Markets LLC
Hi, guys. Can you talk a little bit about the flow back period and initial production that you're seeing on the extended reach laterals compared to your standard length laterals?
We've heard from some of the other peers out there that the longer laterals may take a little longer to cleanup and then kind of a flatter decline, so just curious what you guys are seeing on your end?
Scott J. Reasoner - Senior Vice President-Operations
This is Scott. And then hopefully, I can point you in a direction there that's meaningful.
We look at this in the flow back process as using a similar choke size as to what we would use in a standard length lateral. So by sheer physics, we're holding back those wells more than we would if we went to their capacity, I guess, if you want to see that.
We do that because we do want to manage our liquids – our liquids fallout in the rock that type of thing early in the life of these wells and we do that both in the Wattenberg and in the Utica. In terms of cleanup time, we do see a little bit more time and it's again basically the process of moving as much water as we put in there.
And when you add 20% to the fluid volumes that you pumped in there, you've got 20% more to get out, so it does take a little bit longer. I don't have a specific amount of time there to give you, but we do see that.
We see similar cleanup processes though the oil coming online and gas taking a little longer – oil coming online early and the gas taking little longer to get up to its full capacity there is really what we see in both those cases.
Jeffrey R. Connolly - CIS Capital Markets LLC
Thanks, Scott. That's really helpful.
And then one more on the Utica with well cost down to $7.5 million to $8 million, at current prices, where do you guys think the rates of return are?
Scott J. Reasoner - Senior Vice President-Operations
And that's one that I haven't looked at recently. At this point, I would have to see that we're continuing to – we're continuing to look at those numbers.
And I think over the next several weeks as we see the Cole results come out of the ground, we'll be looking more carefully at the rates of return, but I don't have a specific number for you right now. The Dynamites are looking really solid, I would say, we're liking what we see, but I just don't have a rate of return number for you there.
Jeffrey R. Connolly - CIS Capital Markets LLC
Okay. Thanks a lot guys.
I appreciate it.
Operator
Thank you. Our next question comes from Paul Grigel from Macquarie.
Your line is open. Please go ahead.
Paul Grigel - Macquarie Capital (USA), Inc.
Hi. Good morning.
Bart, maybe a high level strategy question for your on CapEx that is coming in a little bit hotter. What's the kind of at least thinking in the near term about balancing to maybe stay closer to the CapEx budget and reducing activity versus kind of continuing the momentum into 2016, a bit more agnostic on commodity prices in that scenario?
Barton R. Brookman, Jr. - President and Chief Executive Officer
Yeah, good question, Paul. I think I go back to really meeting the data from all the pieces and parts that we're talking about.
We're continuing to improve cost structure in the Wattenberg. Some of these completion techniques, line pressure, all of these, and how they add up to longer – longer term, and I'm putting this into 2016 production forecast.
The drilling efficiency is going to be a biggie as we go through the year. Our Wattenberg operating team is just – our drilling group is just killing it right now.
And so we're watching that. So it's a really good question as we layer all these parts together and look at going into 2016.
What will our capital be and what will be our production forecast, and is there a point that we can have our cash flow where it's neutral with our cap spend. I think at Analyst Day and we've been out in the market saying we're going to have modest overspends, and those modest overspends are somewhere around $100 million.
So it's something we're looking at. And obviously if prices were to correct backward on us from current levels, back to say in the high-$40s, we would give some of that strong consideration with our hedges just to be conservative as we go through next year.
Hopefully, I answered your question.
Paul Grigel - Macquarie Capital (USA), Inc.
Yeah, no, I appreciate that. That's helpful.
That was the only one I had. Thanks so much.
Operator
Thank you. Our next question comes from Ben Wyatt from Stephens.
Your line is open. Please go ahead.
Ben Wyatt - Stephens, Inc.
Hey, good morning, guys.
Barton R. Brookman, Jr. - President and Chief Executive Officer
Good morning.
Ben Wyatt - Stephens, Inc.
Just a follow-up here on the questions about 2016. Bart, you've added some more stuff talking about the drilling efficiencies you guys are seeing.
You also mentioned a laundry list of other things that would dictate whether you accelerate in 2016. But just curious from a – maybe from a well backlog standpoint, are you guys modeling where you're building maybe a bigger backlog of uncompleted wells as you kind of near the end of 2015, so you can't step on the gas a little faster in 2016, or the backlog looks similar at the end of 2015 as they did it in 2014?
Scott J. Reasoner - Senior Vice President-Operations
Ben, this is Scott. And I'll try to do this justice and then Bart can run with it from there.
When we look at our backlog, we really go through phases of limited completions. And then as we get a group of wells in an areas as we have in the Churchill and Chesnut area, we do a significant number, and it seems like it's going to go that way this year as we move through the third quarter, we'll have fewer wells on the completion side.
And then, in the fourth quarter, we'll step it up again. But we really are – our backlog is more a function of our drilling pace than it is the – any holding back.
Our logistics are such that we schedule these and try to execute them as soon as we feel like we're ready is from a drilling perspective, and that's really the approach we're taking. I know there are companies that – that are looking at this and holding back completions.
And we just see that our economics are so solid right now that we can keep right on rolling and not have to try to manage through the price situation as unpredictable as it is seeing oil where it is today, is one of those things that surprises me a little bit, but it moved up as much it has. But that's really the way we look at it.
So, Bart, did you have anything else to add?
Barton R. Brookman, Jr. - President and Chief Executive Officer
No. I – probably, the only add to that would be, obviously, if we go to six rigs in Wattenberg, we're going to increase the backlog.
I can't tell you this, our budgeting team and our operating team do a phenomenal job of literally mapping out every pad in the budget process. Our permits are out two years.
We've got a really good handle of the size of the pad. Size of the pad can dictate that backlog.
But when we have a steady rig pace in a basin, generally from a satellite view, you've got pretty consistent carryover year-to-year of uncompleted wells. That can obviously change with drilling efficiencies which Scott touched on, I touched on, that's something we'll altogether in our budgeting process so that might be a slight uptick to that number.
And then if we were to add rigs, you'd have another uptick. But overall as Scott said, we're trying to complete these pads as efficiently as we can in a timely fashion after the drilling – after the drilling was completed.
And then our teams have got a relatively smooth process right now of getting them online, which is an important part of this also.
Ben Wyatt - Stephens, Inc.
Very good, guys. Well, appreciate it.
Thanks for let me get in.
Operator
Thank you. We have a follow-up question from Jeffrey Campbell from Tuohy Brothers.
Your line is open. Please go ahead.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Hi. Thanks.
Thanks for letting me back in. Just a real quick one.
Slide 13, all those DRLs that you give such a nice detail on are any of those also be in plug-n-perf completions?
Scott J. Reasoner - Senior Vice President-Operations
It's a great question, and generally we are doing our extended reach laterals with plug-n-perf and then there is some good logic that goes behind that as you get longer laterals that equipment for the sliding sleeves ends up on the outside of the casing, and it becomes more of an issue to slide that in the hole. And so as we've seen an opportunity to simplify that process, we've taken that at the same time, shift over to the plug-n-perf side where we can test that.
So it really makes good sense in terms of the logic behind it. But generally, right now, we're primarily looking at the longer laterals as our plug-n-perf tests.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
So then when we start to get some production results on this, you all be sure to help us bifurcate what might be an uplift simply because of the shallower decline that you expect from the longer lateral and then the enhancement of the plug-n-perf?
Scott J. Reasoner - Senior Vice President-Operations
That's correct. And we're watching that very carefully.
Obviously, that's one of the things that's important to us, this is – these longer laterals, we continue to say they're going to perform economically similar to the standard laterals. We're hopeful that the plug-n-perf will add economics to that such that we're seeing the additional rates of return.
And I know I've mentioned this before, but we don't have any of that volume, that incremental volume associated with the plug-n-perf process and the AccessFrac BioVert process in our expectations for the rest of this year.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
And a real quick follow-up. Earlier in the call, you said that plug-n-perf adds 6% of D&C cost.
Am I correct in assuming that was on a standard lateral, and if so, what would be the cost uplift on the longer laterals?
Scott J. Reasoner - Senior Vice President-Operations
That's correct on a standard lateral. And I would say, it's probably fairly similar on an extended reach lateral.
There is enough extra cost in those stages that it's probably similar. It might be a little bit less in percentage, but similar.
Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.
Okay. Great.
Thank you very much.
Operator
Thank you. I'm showing no further questions at this time.
I would like to hand the conference back over to Mr. Brookman for closing remarks.
Barton R. Brookman, Jr. - President and Chief Executive Officer
Thank you, operator, and thank you, everyone, for joining the first quarter call, and thanks for the ongoing support in PDC.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This concludes our program.
You may all disconnect.