Feb 19, 2015
Executives
Michael G. Edwards - Senior Director of Investor Relations Barton R.
Brookman - Chief Executive Officer, President and Director Gysle R. Shellum - Chief Financial Officer Scott J.
Reasoner - Senior Vice President of Operations Lance A. Lauck - Executive Vice President of Corporate Development and Strategy
Analysts
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. David R.
Tameron - Wells Fargo Securities, LLC, Research Division Ipsit Mohanty - GMP Securities L.P., Research Division Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division Blake Donovan - Stifel, Nicolaus & Company, Incorporated, Research Division Irene O.
Haas - Wunderlich Securities Inc., Research Division Michael A. Hall - Heikkinen Energy Advisors, LLC Michael S.
Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division Ben Wyatt - Stephens Inc., Research Division
Operator
Greetings, and welcome to the PDC Energy 2014 Fourth Quarter and Year End Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host, Mr. Michael Edwards, Senior Director of Investor Relations.
Mr. Edwards, you may now begin.
Michael G. Edwards
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, which is www.pdce.com. I'd like to call your attention to our forward-looking statements on Slide 2 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 those non-GAAP financial measures.
With that, let's get started. I'll turn the call over to Bart Brookman, our CEO.
Barton R. Brookman
Thank you, Mike, and welcome, everyone. Let me start with a few opening comments.
PDC begins 2015 in a uniquely positive position. While we recognize the severity of these market conditions, the company's business plan remains growth focused, and we will continue to deliver value to our shareholders.
Several factors contribute to our resiliency. First, a very strong balance sheet with ample liquidity.
Gysle will cover this in a lot more detail in a moment. Next, a top-tier hedge program.
Significant hedges are in place which give us financial security through year end 2016. We are seeing the capital structure on our drilling programs improve dramatically, resulting in ongoing value-add drilling, particularly in the Wattenberg Field.
And last a talented technical and financial and land group to execute on the company's business plans. Let me give some details around our 2015 forecast.
First, our capital program improvements. Our CapEx budget for 2015 has decreased $84 million to $473 million, a considerable adjustment from our previously announced $557 million.
The improvement is primarily due to a reduction in the drilling and completion cost structure in the Wattenberg Field and an anticipated slowdown in non-operated activity. We're pleased our production guidance continues to hold at 50% production growth for 2015 when compared to '14 levels.
The liquid mix for the company remains 65%. And we have slightly widened our guidance to a range of 13.5 million barrels equivalent to 14.5 barrels.
This is due to the uncertainty of the non-operated activity. Our balance sheet.
Year end 2014, liquidity of $650 million and our estimated year end 2015 debt-to-EBITDAX ratio will be approximately 2.0. The company will continue to honor the balance sheet as we execute on our capital programs.
The cash flow for 2015 is estimated to be approximately $360 million at the midpoint of our production guidance. This is based on $51.72 oil price and a $2.86 natural gas price.
And the outspend for the company has been reduced to $110 million. Next, let me talk about hedges.
For 2015, we are 85% hedged on oil at an $89 per barrel level; 75% hedged on our natural gas at approximately $4 per Mcf. Additionally, we have significant volumes hedged in 2016 at $85 oil and $4 in Mcf.
And last is the strength of our drilling programs, with the improvements in our per-well cost structure, including the technical improvements that Scott will touch on in a moment, the inner and middle core areas of the Wattenberg Field at flat NYMEX $60 and $3.25 natural gas are expected to deliver internal rates of returns somewhere between the low 40% and the high 60 percentile. Now let me cover some highlights from 2014.
Strong production, 9.3 million barrels from continued operations of 42% overall growth rate from 2013. Our oil and gas revenues for the company increased 38% and our lifting cost per Boe decreased 9%.
Scott will give a lot more detail around this in a moment. The adjusted cash flow for the company increased to approximately $250 million, an increase of 20%.
And the company's year end 2014 debt-to-EBITDAX ratio was 1.9x. The Marcellus Shale divestiture for $250 million resulted in $192 million net proceeds for our 50% interest in the Marcellus assets.
$153 million of this was cash, a timely strengthening of our balance sheet. We also have a $39 million note outstanding with the buyer.
And this transaction did result in a $76 million gain. And now our reserve report.
Year end 2014 proved reserves increased to 250 million barrels equivalent, an 11% increase after adjusting for the Marcellus divestiture. 65% liquid mix remains for the reserve report.
And we had a 360% reserve replacement for the company. And once again, our hedges.
The company is significantly hedged for 2015 and '16. And we ended the year with a $300 million fair value on our hedge positions.
So in closing, I would like to thank all of the PDC employees for their efforts in 2014. PDC is very well-positioned to continue our growth in the future.
Those are the highlights. And with that, I'm going to turn the call over to Gysle to cover financial details, which will be followed by Scott to cover the operational update.
Gysle R. Shellum
Thanks, Bart. Good morning, everyone, and thanks for joining us this morning.
As always, my comments will be high level. So for more complete analysis of our fourth quarter and full year 2014, please see our press release and our 10-K that were filed this morning.
I will also provide preliminary financial guidance for 2015 based on updates to our capital plan and production. I will summarize 2014 as a year, where PDC focused on organic growth and streamlining our portfolio by completing the divestiture of our last dry gas asset, our interest in the Marcellus joint venture, which helped fund our 2014 Wattenberg and Utica capital programs.
Production from the fourth quarter was 2.6 million barrels of oil equivalent. And for the full year, it was 9.3 million Boe from continuing operations, as Bart noted.
Our fourth quarter reflects the success of both programs with record crude oil production in Wattenberg and a new high in Utica. This was in spite of some severe winter weather in Colorado and some midstream issues in the fourth quarter that resulted in delays to our turn-in line schedule and production.
Production for the year, however, still came in within our range of guidance. As for financial results, we had a strong first 9 months, then saw the impact of price declines in October and November, with prices plummeting in December.
2014 crude oil price averages had been higher through 9 months of the year compared to 2013. Then in the fourth quarter, we saw oil prices averaging about 31% lower than the fourth quarter 2013.
We still saw strong growth year-over-year in our adjusted cash flow from operations and adjusted EBITDA. That's the high-level summary.
Now I'll get into some of the metrics for the fourth quarter and the full year 2014. The story for the fourth quarter oil and gas sales was mostly production growth and deteriorating commodity prices that led to a drop in sales compared to the third quarter of 2014 as well as compared to the fourth quarter of 2013.
Sales from continuing operations for the fourth quarter were down 12% from the fourth quarter 2013 due to a steep drop in oil prices, though higher volumes in the fourth quarter 2014 compared to the third -- fourth quarter 2013 helped minimize the decrease in sales. Natural gas prices were up slightly in the fourth quarter 2014, while NGL prices followed oil prices ending down 29% from the same quarter of 2013.
Production from continuing operations increased 24% to 2.6 million barrels of oil equivalent during the fourth quarter 2014 compared to the fourth quarter 2013. The increase in production helped offset the 29% decline in prices on a Boe basis.
The increase in realized hedged gains of $19.2 million in the fourth quarter 2014 compared to the fourth quarter last year more than offset a $14 million drop in oil and gas sales in the fourth quarter 2014. The average full year prices for crude oil were down 10% compared to 2013, and natural gas liquids were down just 2%.
Average natural gas prices, however, were up about 20% year-over-year. The year-over-year price decreases in liquids were offset by a 42% increase in production from continuing operations year-over-year, resulting in a 38% increase in oil and gas sales before realized hedging gains in 2014.
Net realized hedging losses, which we now call, net settlements on derivatives on our filing documents, were about $1 million for the year 2014 compared to about $11.2 million in 2013. Production costs from continuing operations on a per unit measure moved down about 23% quarter-over-quarter.
Production costs included lease operating expenses, production taxes, overhead and some transportation and processing costs in Utica. For the full year 2014, we averaged $9 per barrel of oil equivalent, almost $1 lower than last year.
For the fourth quarter 2014, we averaged $7.36 per barrel of oil equivalent, more than $2 lower compared to the same quarter last year. Fourth quarter decrease is primarily due to flood costs incurred in the fourth quarter of 2013.
Scott will talk more about lease operating expenses in a few minutes. The gross margins were 82% of sales for the year end 2014 compared to 81% for 2013, again before realized hedged gains.
Fourth quarter margins were down slightly to 81% in 2014 compared to last year's fourth quarter margins of 83% due to decline in commodity prices. We had several events in 2014 that impacted our GAAP financial results, including the gain on sale of our Marcellus assets that Bart mentioned, settlements of litigation and the drop in oil prices that dramatically impacted unrealized gains on our hedge positions and led to the impairment attributable to our Utica properties.
I'll discuss these events in conjunction with our non-GAAP results on the next slide. Adjusted net loss of $39.9 million in the fourth quarter was impacted by the after-tax gain on the sale of Marcellus assets of $76.3 million, offset by tax of about $29.9 million on the gain.
The quarter was also impacted by the impairment of our Utica properties of $158.3 million, offset by $62.1 million tax benefit. Without these events, adjusted net income for the quarter was $10 million.
Adjusted net loss of $37.7 million for the full year 2014 includes the impact of the same two events I just mentioned and includes legal charges of $43 -- $40.3 million, offset by $15.9 million in tax benefit. Excluding these three nonrecurring events, adjusted net income was $36.3 million for the year.
Adjusted cash flow from operations is defined as cash flow from operations excluding changes in working capital. Adjusted cash flow for the quarter was $70 million or $1.94 per diluted share.
For the full year, adjusted cash flow was $250.2 million. However, if you exclude the $40.3 million litigation charge recorded in G&A in the first 9 months of 2014, adjusted cash flow was $290.5 million.
The upward trend for the year reflects the production volume growth, which pushed oil and gas sales higher for all but the fourth quarter of 2014. Adjusted EBITDA in the current quarter was up almost 100% compared to the fourth quarter 2013.
And the full year 2014 was up 50% compared to the full year 2013. These numbers include the gain on sale and the legal charges I mentioned.
When we adjust for the $76.3 million pretax gain on sale in both the quarter and year and adjust for the $40.3 million of litigation charges, fourth quarter 2014 adjusted EBITDA was $83 million. And for the full year 2014, it was $325 million.
Adjusted EBITDA per diluted share also includes both the gain on sale and legal charges. Moving these 2 amounts, the adjusted per share numbers were $2.30 and $8.86 for the fourth quarter and the full year of 2014, respectively.
DD&A includes depreciation of fixed assets and depletion of oil and gas properties. The decrease in 2014 compared to 2013 -- the increase in 2014 compared to 2013 is due to both the increase in production and the increase in the overall DD&A rates year-over-year.
Per unit depletion rates on just oil and gas properties for the fourth quarter and year ended 2014 were $19.11 and $20.28 per Boe, respectively. That compares to $16.33 and $75 -- $17.05 for the fourth quarter and year ended 2013.
The increase in the rate during the fourth quarter 2014 compared to the fourth quarter 2013 was because of higher depletion rate attributable to our Utica production. G&A increased in 2014 compared to 2013, mostly because of the $40.3 million litigation charges.
Apart from that, there was an increase in stock-based comp, a noncash charge and some increase parallel to employee benefits. 2 years ago, we extended the maturity of PDC's revolver to 218 -- to 2,018 and have maintained the borrowing base at $450 million, up until our fall 2014 redetermination when it increased to $700 million.
And we elected to limit the lenders' commitments to $450 million. Our credit agreement calls for redeterminations in May and November.
And we've been evaluating the impact of lower commodity prices on the borrowing base redetermination this spring. Due to increases in proved reserves, we don't expect lower commodity price decks to have a significant impact on our borrowing base.
We began 2014 with $193 million of cash, which along with cash flow from operations and the proceeds from the sale of the Marcellus assets, funded our 2014 capital program. We were drawn $56 million on the revolver at year end and had $16 million in cash.
As Bart mentioned earlier, we expect capital expenditures to outspend 2015 cash flow by about $100 million to $125 million. The table on this page reflects PDC's borrowings.
Liquidity including cash on hand and the available $700 million borrowing base at December 31, 2014, was approximately $648 million. Our hedge positions for 2015, 2016 and 2017 are shown on this page.
We are substantially hedged for crude oil and natural gas production volumes for 2015. We have about 85% of our expected crude oil volumes hedged at a weighted average price of $88.61 per barrel.
On gas, we had about 75% of expected volumes protected at a weighted average floor of $3.90 per MMBtu. For 2016, we have 4.1 million barrels hedged, about 80% of our total hedge volumes that we have in 2015 at weighted average floors of $88 -- $84.99 per barrel.
For natural gas, we have about 30% more volumes hedged in 2016, and this year at a weighted average price of $3.89 per MMBtu. We have some good volumes in natural gas slide for 2017.
But we've not seen any opportunity to layer it much in the way of crude oil hedges for that year. Our last slide is our financial guidance for 2015.
We came out with initial guidance in early December on capital expenditures and production. As Bart mentioned, we lowered our capital expenditure guidance due primarily to results -- reductions in service costs.
We maintained our production guidance just widened in the lower end of the range, 13.8 million barrels of oil equivalent to 13.5 million due to the uncertainty in the level of timing of non-op activity. Beside lower cost assumptions, we also lowered our price assumptions from those we made in December.
We're now using average NYMEX prices of $51.72 per barrel for oil and average gas prices of $2.86 per MMBtu for natural gas for the year. We expect oil differentials to the wellhead to be around $9 to $10 per barrel in 2015.
Based on the production ranges, we forecast sales to be between $361 million and $400 million, with realized gains on derivatives of $188 million using the average price I just mentioned. Adjusted EBITDA is forecast between $386 million and $413 million.
Our adjusted cash flow from operations are expected to be between $350 million and $375 million or $9.41 and $10.10 per diluted share. Based on this range of outcomes, we project the draw from our revolver to be between $180 million to $205 million at year end 2015.
And as Bart mentioned, we expect to end the year with a conservative leverage ratio of around 2x debt-to-EBITDAX. With that, I'll turn this over to Scott for a discussion of our operations.
Scott J. Reasoner
Thank you, Gysle, and good morning, everyone. We had an excellent year end 2014.
And I do want to thank our land, EHS and operating teams for all their efforts. As Gysle noted, production for 2014 was 9.3 million barrels of oil equivalent or 25,464 barrels of oil equivalent per day.
This is a 42% increase from our 2013, based on continuing operations and fell within our guidance range. And that's despite fourth quarter challenges related to weather and third-party midstream.
In particular, the Wattenberg Field production increased 43% in 2014, which shows the continued growth potential of this asset. Continuing on to production highlights.
One key point of highlight here is the addition of our fifth rig. The rig drilled the significant pad, our first in the inner core, which turn -- with the turn-in line date late in the fourth quarter, contributing 1 or 2 months of production.
These results have been very encouraging as you'll see in a few minutes. As we move into 2015, we have the carryout from all 5 rigs as well as their activity to drive production growth in 2015.
We continue to grow our liquids production, which averaged approximately 17,756 barrels per day in the fourth quarter. Liquids represent 65% of our production for the year.
We promised the strong production jump in the fourth quarter and delivered, as is reflected in the lower right bar graph. We did have some headwinds we were fighting in that we had very cold weather in Colorado in mid-November and late December.
There were also delays in third-party midstream startup and had a general increase in line pressure due to DCP capacity limitations that also impacted the quarter. Our production continues to show a slightly higher GOR than budgeted.
Our current crude oil type curve reflects the entire field and is not representative of where we are drilling -- of where our drilling is currently focused, which is in the gas tier [ph], inner and middle cores. In addition, the inner core Codell wells are showing higher GORs than the Niobrara counterparts.
In 2015, we have accounted for this in our forecasting by more accurately determining GOR by specific pad. Now discussing the 2015 production expectations.
First quarter 2015 DCP line pressure has continued to be high. As with last year, our production team has continued to stay on top of this ongoing issue.
DCP's Lucerne plant is still on schedule for the second quarter of '15 and should relieve the continually increasing high line pressure we have been seeing. As the rig count comes down, the relief will be longer lasting.
I want to point out that the greater range for our revised forecast of 13.5 million to 14.5 million barrels of oil equivalent is associated with adjustments in turn-in lines and the expected reduced activity and greater uncertainty in the non-op category. But we are still holding our 50% production growth expectations.
One final note on production. We are not providing quarterly production guidance due to all the moving parts, including longer times -- time periods to drill and turn-in line extended reach laterals as well as higher line pressures prior to the startup of the Lucerne 2 plant.
I can tell you that we expect a modest production increase from Q4 2014 to Q1 2015, a big step in Q1 to Q2 and Q2 to Q3 and then a relatively flat Q3 to Q4. Let me give you -- let me give a review of our reserves we announced several weeks ago.
Year end 2014 reserves came in at 250 million barrels of oil equivalent, an 11% increase over our 2013 level, once you account for the sale of Marcellus. These are 64% liquid, with the before tax SEC PV10 value of $3.5 billion.
Of note, we have stress tested these all the way down to $50 oil due to the difference in the current pricing environment and the SEC price that was used. In such a scenario, less than 9% of our proved reserves were affected.
I now want to focus in on our Wattenberg technical projects. Our technical testing continues to pay dividends in the overall performance of this drilling program.
Our first 20-well equivalent project, Sunmarke, is on line with limited data but early results are positive. We've drilled and completed 4 Niobrara and 4 Codell wells on this half section with 32-acre spacing.
Our Guttersen test has been revised to compare our standard hybrid completion fluid to a bio-diversion product in that hybrid fluid. The purpose of the bio-diversion material is to contact more rock face with the same frac volumes.
We have also completed the maxi wells to compare a plug-and-perf completion to our standard sliding sleeves. The early production from each of these shows potential to improve.
[Technical Difficulty]
Operator
Ladies and gentlemen, please stand by. Your conference call will resume momentarily.
Once again, please stand by. Speakers, you are live.
Please proceed.
Scott J. Reasoner
We're finishing drilling in the Chestnut and Churchill 20-well spacing equivalent test and we'll begin completion of these wells in March. The graph on the lower right of the slide shows results from our first 9 inner core well relative to our recently revised inner core type curve.
The early data from these wells is right on our 580,000-barrel type curve. We have budgeted 2 further downspacing projects in 2015, a 22-well per section equivalent, which is 11 wells on a half section and a 26-well per section equivalent, which will be 13 wells on a half section.
These wells will continue to expand our knowledge of downspacing potential in the Wattenberg Field. Now a quick look at the changes to our economic profile.
We have a number of changes to our economics with the market correction. This comparison is of the $60 per barrel and $3.25 per MMBtu NYMEX price.
I want to emphasize flat pricing. In addition to the commodity price reductions, these economics are a reflective of 5 key economic uplifts.
First, the positive offsets from a 16% reduction in cost. Second, increased stage density.
Third, longer laterals. Fourth, updated inner core type curves.
And finally, our 2015 focus on middle and inner core wells. As you can see, all of these economics reflect a rate of return well north of 40%.
And even at an oil price near $50 per barrel flat, we'll still be very economic. Our Utica land team has been very effective at blocking up our acreage position and the operations team improving the productivity of these wells over the last year.
We have settled in at approximately 67,000 acres and 220 locations. Our 4-well Dynamite pad early production is shown on the graph on the upper right side of the slide relative to our 680,000 barrel type curve.
The average of the 4 wells is performing above our type curve. And it appears that the separation will become greater over time, confirming our expectations that these wells will outperform our prior wells.
These 4 wells are already in the top 5 wells we have drilled in the northern part of the play, showing that we continue to improve on our results. We continue to expect improvements in this play, as we are still very early in our development.
In addition, based on efficiency and service cost reductions, the costs have come down approximately 20% with room to move further. We will begin fracking the coal pad early in March, and we'll be applying our knowledge from the Dynamites to these completions.
Although we do not have a rig scheduled for drilling in this area, the improvements continue to excite us about the longer-term potential of the Utica. Now a quick overview of the drilling activity for 2014.
The company operated spud count was 127 horizontal wells. 116 of those were in the Wattenberg Field and 11 in the Utica.
30 of the 116 Wattenberg spuds were extended reach laterals. The company also participated in 84 non-operated projects, giving a total project count of 211 in 2014.
Moving on to 2015. We have budgeted 119 operated wells, 65% of which will be Niobrara's.
We have revised our budget to 85 non-operated wells in the Wattenberg Field for a total of 204 drilling projects in 2015. One important note.
Our non-op spud and turn-in line count will be impacted by the 2015 plans of our Wattenberg peers. We have yet to see all of their budget releases but are in constant communication with them.
We continue to run 5 rigs in the Wattenberg Field and are getting an opportunity to upgrade our fleet to all flex rigs. A few comments on LOE.
Fourth quarter numbers continue to trend down as a result of higher production and some reduced cost. Overall, for 2014, our cost settled at $4.36 per Boe.
For 2015, we have a guidance range of $3.39 to $3.75 per Boe, an 18% reduction in per unit LOE to the midpoint. Increased production and cost reductions associated with the commodity prices falling both contribute to this, although we do continue to see upward pressure from the regulatory side.
We are also revising our 2015 budget from $557 million to $473 million to reflect cost savings associated with negotiations with our Wattenberg suppliers of approximately 15% -- I'm sorry, 16%, with more expected as we continue our negotiations with some vendors. Reduced non-op spend from initial discussions that we have had with several of our peer companies and increased working interests.
Our current cost for Wattenberg standard laterals is $3.6 million and an extended reach lateral is $4.6 million. At this point, 92% of our budget is focused on high-quality Wattenberg projects.
We are pleased with the cost structure improvements while maintaining our 50% production growth expectations. Here you see a recap of some of the highlights I just covered.
Again, 2014 was a strong year for us. And we are confident in our plan for 2015.
With that, I'll turn the call over to the operator to begin Q&A.
Operator
[Operator Instructions] And our first question comes from the line of Ryan Oatman with SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Bart, I was wondering if you could speak to the technical improvements you're making in the Wattenberg. Last conference call, you sounded most confident about stage length modification in my opinion.
Do you feel like 200 feet between stages is about right? Or have you been encouraged by what you're seeing from the 150 foot test, et cetera?
Scott J. Reasoner
Ryan, this is Scott. I will say that we definitely are encouraged by what we're seeing as we continue to down space.
The results continue to show improvements. I'm not sure where we'll settle in terms of the lower end of that number, but at this point, we're encouraged.
I think in addition to that, some of the other things we've tested recently on our completion methodologies, the different types of fluids, that type of approach has also been very encouraging and may make a difference in our future as we go forward.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
That's helpful. And this might be a question for Lance.
The press release mentioned the higher working interest in your operated area. I was wondering if you could just speak to the competitive landscape and how operators are reacting to this downturn.
What you're seeing on the ground from a leasehold, nonconsent, M&A perspective?
Lance A. Lauck
Yes. So overall, when we talk about the increase in working, just to start with on our operated wells that we're drilling, these are opportunities where we've actually been able to do a few small trades and increase our interest within pads that we're drilling for 2015.
And so that's a very positive add for us there as well. I think as far as the overall levels of activities, I think we're finding more and more out as more companies in the basin begin to release their 2015 drilling programs for the Wattenberg Field.
And we're seeing some reductions by other operators within the field. As Scott talked about, we think that's beneficial to us, definitely on the cost side.
And then also, there may be opportunities that some parties may elect to go nonconsent when we provide an AFE to them to drill the well. So that could also result in us picking up some incremental interest as well.
As far as overall, sort of A&D type lease acreage, the core area of the field, Ryan, it's just pretty well blocked up. The area that we kind of put the box around and talk a lot about, the strength, the repeatability, the great economics that we see there, that's pretty well locked up.
So there's not a lot of real moving parts as far as new leasehold that's in that area. So I mean clearly if opportunities become available in that area, clearly, we would take a look at it and see how it fit within our portfolio.
But we don't see a great deal of acreage that's become available in the core. It tends to be more stuff to sort out and send to the extension areas that other operators are pursuing.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay, that's helpful. And then I wanted to touch on the cost reductions on the Wattenberg going from $4.3 million to $3.6 million.
It looks like you're seeing 15%, 20% reductions in the Utica as well. I was wondering if you can kind of speak to any differences in what's driving those cost reductions that you see between the 2 areas that you're operating?
Gysle R. Shellum
A couple of comments to that. I would say in Wattenberg, it's pretty much across-the-board reductions.
We're seeing most of our suppliers recognize the circumstances that we are in as an industry today and have had good conversations and obviously have seen the benefit of those in terms of cost reductions. When you look at Ohio, a couple of things are happening there.
First of all, I think the prices were probably more -- much greater there because of the amount of work that was going on in the Marcellus as well as the Utica. So we are seeing a little bit more downward pressure there, although it's still early because there are a number of completions that are backed up out there yet that probably still need to get pulled out of the queue before we really see the full benefit of the cost reductions we have there.
Overall though, our service company partners have been very willing to negotiate. And obviously, they're very much recognizing the differences in where we are today versus where we were 6 months ago.
Operator
Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investments.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Slide 17 outlined four different Wattenberg drilling scenarios. Can you rank them on a percentage basis for the current 2015 program?
Gysle R. Shellum
We have -- in our 119 spuds for 2015, we have about 60% to 65% of those will be Niobrara's leaving; the remainder is Codell's. And then with respect to 40 -- the extended reach laterals, we're at about 40%.
And so that really gives you hopefully, a flavor for where we're headed.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
That's very helpful. When will you be drilling entirely with the flex rigs that you mentioned?
Can you comment on any day rate differences between those rigs and the ones that were replaced? And what kind of gain or rig efficiency are you expecting once you're all on flex rigs?
Gysle R. Shellum
We are seeing the -- the flex rigs -- we've already moved one in and have a second one that will be on the way here shortly, or we are moving one in here shortly. And the second one will be on the way in the next 2 weeks.
I think the third one is scheduled for the middle of March, that kind of time frame. And that gets us then to where we are all flex rigs.
When you start talking about cost reductions, we've seen them in those -- in that range that we're talking. That 16% is a pretty good estimate of the overall cost reductions.
And as far as the efficiencies, we've been running a couple of those flex rigs. And then we had the 3 that were non-flex that we're replacing.
And we do see some benefits, although I don't expect a lot out of that early because we will have some inefficiencies as we move those rigs into our operations. I believe all 3 of them are coming from a local -- other folks' land rigs' down.
So we benefit from other players within the Wattenberg not keeping those rigs. And that will give us some advantage where we won't -- where we don't have nearly the inefficiency when you -- typically, when you bring a rig in from outside the area that you're working in, there are some inefficiencies that occur.
So some efficiencies, but I don't expect a lot relative to what we've been doing at this point.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Okay. And if I could ask one last one on the Utica.
2 parts here. One, is coal pad still expected to be completed on schedule?
And just generally, what do you need to return to drilling in the play?
Gysle R. Shellum
Now the coal pad we're going to begin fracking right after the 1st of March. And we'll be turning those wells in line in May and expect obviously, as I said, continued improvements in our productivity up there.
In terms of returning to drilling, we're continuing to work on the cost side, obviously. And as we see more data coming out of the coals in the Dynamites, we'll be more excited about the economics at that point, I think with even where we are today in that 60 to 70 barrel -- dollar per barrel range.
We'll start to see it look like it's a positive economic picture. And it's still -- that's still -- we got to get some adjustment in capital cost to get there.
Operator
Our next question comes from the line of David Tameron with Wells Fargo.
David R. Tameron - Wells Fargo Securities, LLC, Research Division
Can you guys address what are you seeing as far as current economics in the DJ? And getting at x hedges, what do they look like, given current pricing, less deduct?
Gysle R. Shellum
I think our Slide 17 really reflects our current economics and does not include our hedging position. We're really looking at economics during that 40% plus range.
And I think we still have room to improve somewhat on our capital side. So I think we continue to see those pushed up.
If you drop that down into the $50 per barrel range, you'll probably lose 8% rates of return, maybe a little more than that, depending on which set of rates of return you're looking at. But I think that's pretty reflective of where we are today.
David R. Tameron - Wells Fargo Securities, LLC, Research Division
Okay. So that's the $60.
So you said if we go down to $50, we lose 8%. That's helpful.
And then have you guys thought about -- there's a lot of bigger competitors that are deferring completions. Have you guys thought about that?
And just kind of waiting for some of these, I guess you could cash out some of the hedges if they're -- if you end up overhedged on the production side. But can you talk about your thought process around that?
Lance A. Lauck
David, we've talked about it. But the strength of our balance sheet, our hedge position, thinking long term and also a lot of our completions are really building towards next year's production profile, especially in the second half of the year.
So right now, we're not in a position where the returns we just talked about are such they're adding value. So we really treat our operations as a going concern.
I think the second part of that question is it's incredibly disruptive to our operating team to turn it off. We get into a very cost-efficient systematic approach to drilling, preparing for completion and completion and putting them to production.
And we've got groups of people that literally move from pad to pad. And it would be very cumbersome for us to shut it down and then wait for prices and then try to bring it back online.
So we just feel like our best plan is just a going concern as a company and keep, as Scott said, keep pushing on the cost structure.
Operator
Our next question comes from the line of Ipsit Mohanty with GMP Securities.
Ipsit Mohanty - GMP Securities L.P., Research Division
You had about 90 locations in your inner core last Analyst Day. I'm just curious how many of them are still left for '15?
In other words, out of the, call it, 70-odd Niobrara locations that you'll drill in '15, how many of them are going to be inner core?
Gysle R. Shellum
I don't know that I have a specific number for you in terms of the number that we're going to drill in the inner core for 2015. But the bulk of those are left; we may have 4 or 5 of those on line at this point.
So we're probably looking at 85 or so yet to be turned in-line. And really the drilling program for those areas are going to -- for that area is going to be over the next 2 years, 2.5 years.
We'll utilize our drilling rigs to drill the remainder of that 85 count. So I hope that gives you a good flavor of where we're at.
Ipsit Mohanty - GMP Securities L.P., Research Division
Where I was going with this is your -- again, I mean the oil rig [ph] might have improved. But for the inner core, it was around 23%, 25%.
So I'm curious if that features in your drilling program for this year, what will your commodity mix in the end of '15 looks like?
Lance A. Lauck
We will -- I think our commodity mix will look like about flat for the year, about 65% liquids for the year. And that's because we're not just drilling in that inner core.
We're also drilling in the middle core. We do have a few wells in the outer core that we're drilling this year as well.
So it really becomes a circumstance where because of that mixture as well as our current PDP production, which is very predictable GOR as well, we will have, I think, flat, really flat in terms of the liquids production for the year.
Barton R. Brookman
Ipsit, let me just add one thing to this. We'll be 65% liquid mix for 2015.
We've adjusted that guidance with all of the recognition of Codell performance, Codell cleanups, inner drilling, more inner/middle drilling, high-grading our drilling programs. So that mix, our reserve group and modeling group have dedicated an incredible amount of time to try to peg that number.
So expect that to be 65% liquids. I know there are some questions in some of the releases this morning around the oil.
There will be about 45% oil, 20% NGLs, and the balance will be natural gas. And I think those are pretty strong numbers when the market looks at our overall commodity mix for the company.
As Scott said, that changes a little bit. But overall, when we blend our drilling programs in the way they're going to be executed, expect that to be within 1 or 2 points of accurate.
Ipsit Mohanty - GMP Securities L.P., Research Division
That answers my question, Bart. And my last one, in one of your slides, you show a big improvement in your IRR in the inner core.
Well, across cores, but mostly in the inner core. Is that because of the type of revision?
Or did you see any improvement in [indiscernible] or anything else?
Scott J. Reasoner
When you look at those economics, they're reflective of all of the efforts that took place. So it does take into consider the CapEx reduction, the increased stage density and the inner core type curve.
The combination of those 3 things are really what make up that variation. So that's why the bigger adjustment there.
Ipsit Mohanty - GMP Securities L.P., Research Division
So as you go, you go through '15, when you go back to '16 and beyond, you again go back to -- you're looking at your inventory, you probably go back to your middle and outer core. Is it reasonable then to expect that your oil improves, your liquid field improves?
But the EURs come down? In other words, the overall EUR of Niobrara comes down in the future?
Scott J. Reasoner
Your statement is correct. We're looking at approximately 2,600 wells in our 2P.
Of those, 1,900 are in our middle and inner core. We're going to use up that inner core over the next 2 years in our drilling program.
Really, we'll be focused in on that middle core, which will be much more reflective of the rate of return and the GOR of the middle core type curves that we've shown in the past.
Operator
Our next question comes from the line of Welles Fitzpatrick with Johnson Rice.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
Can you guys break out a little bit the $84 million drop in CapEx? How much of that was cost-related?
Maybe what percentage drop that, that envisions? And then how much of that was non-op related?
Gysle R. Shellum
Yes. The CapEx adjusted downward about $30 million for non-ops, just based on their -- on our, I guess, the first pass and what our expectations and what our partners will do.
Then overall, we took a 16% reduction in costs to reflect the next step. And then as Lance was talking about earlier, the remainder is an increase really in working interest in what's primarily the Chestnut and Churchill area.
We've been drilling in and referenced a number of times. But we're really excited about adding interest there because we're going to get greater rate of returns on those projects.
So combination of the 2 downward forces and then the upward force with the working interest change.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
And that leads to my next question. Obviously, it's pretty tough to guestimate, but as far as the net acreage that you could add with that working interest shift, is that a couple of hundred acres?
Is it a couple of thousand?
Barton R. Brookman
I'd say in general on these wells that for what we're looking at this year, it doesn't require a significant amount of acreage to add to the cost that Scott is talking about because once again we're drilling so many wells in the per section type of basis and all of that. So it's a small number.
It's probably on the neighborhood of 500, 600 acres, plus or minus to kind of...
Operator
Our next question comes from the line of Blake Donovan with Stifel.
Blake Donovan - Stifel, Nicolaus & Company, Incorporated, Research Division
You mentioned 40% of your 2015 program is going to be dedicated to extended reaches. Is this program limited by the layout of your acreage?
And if so, would acquiring or swapping, blocking acreage incline you to expand the program in the future?
Scott J. Reasoner
We are somewhat limited by the layout of our acreage. But we can always combine acreage, and that's typically what happens irrespective of the current position we're in is we'll combine acreage and join forces.
The reverse of that also happens. Other operators combine our acreage into theirs and drill laterals and some regular link laterals, some longer link laterals.
Really, we're looking at this from a standpoint of where can we be most efficient with the work that we're doing. And so we're in -- in the circumstances that we're in over the next couple of years, we're looking at that 40% range as a pretty good estimate of what our extended reach laterals will be.
And the answer to your question on would swapping add to the potential to add more extended reach laterals? The answer is yes.
And we're constantly looking at that. As Lance pointed out a few minutes ago, we've been working on one that actually added to some of the wells that we already have.
And we continue to work on that. It's something that we've just dabbled into at this point.
Blake Donovan - Stifel, Nicolaus & Company, Incorporated, Research Division
Great. And then not to get too far in front of our skus [ph] here.
But let's say in a scenario where your 2015 capital spend comes in considerably less than your budget and -- or you have potentially higher anticipated cash flows due to a second half recovery? Would you consider using the excess availability to, say, complete more wells or pursue acquisitions?
Or would you simply try to shrink the outspend?
Gysle R. Shellum
I think the strongest consideration would be to accelerating our development. If we see a commodity price rebound, as Scott noted, we've got our Utica project out there that we will give consideration to.
And we also have additional activity in the Wattenberg Field. I do believe if we see a recovery, we'll also see our non-operated takeoff, and that would eat up some of the additional cash.
And Lance is saying yes, they continue to look at the business development side of things. We do view this as an opportunistic market.
It's not a key part of our strategy right now. But he is absolutely keeping his eye on what we would classify as top-tier deals that may hit the wire that we need to look at.
So we would give some consideration to that also.
Operator
Our next question comes from the line of Irene Haas with Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
This is a question for Scott. You mentioned that your well cost is down to $3.4 million cost in lateral, which is really impressive.
You also alluded to the fact that under regulatory and you have some cost pressure. I would like some color on that particular subject and just wondering what you guys are up against.
And also related to that is this sort of community relations. How's that coming along?
Scott J. Reasoner
I'll start with the regulatory environment and our cost estimates. And hopefully, I didn't misspeak, Irene.
But our standard laterals were at about $3.6 million. So I hope I didn't misstate that earlier.
Our regulatory costs continue to increase as it really is a general increase. There's nothing specific that's come out of the current political environment that we're dealing with.
But just general additional regulatory circumstances that we've been placed in over the last several years, much of which is still around the air regulations that have been changing. And that's the general upward pressure that we're seeing from the regulatory world.
It's such that it's hard to measure going from year to year. But we just continue to feel that as we're seeing the staffing ads, that type of thing that we see in our field operations.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Okay. In terms of community relations, how are things shaping out these days?
Barton R. Brookman
Irene, the State of Colorado obviously has been a challenge the last year. I would say we have much calmer waters right now than we did a year ago.
We've got -- as you know, the 20-person commission that is diligently working towards some resolution around urban planning and drilling closer to urban communities. We expect some decisions out of that group, I think, over the next month.
We're keeping a close eye on all that. So I would classify things as fairly calm right now but active in Colorado.
The industry continues to be out trying to educate the public about the benefits of the industry, the safety aspects of the industry. I think we're doing a good job with that.
And I think we're gaining some traction. And so we don't feel any severe pressure on our capital programs or anything like that.
But the company continues to work with the other operators in trying to really promote this industry in the State of Colorado and also be very involved on the political end. So anyway, that was kind of a long-winded, fairly vague answer.
But it's a challenge, and it's something we expect to continue in the future.
Operator
Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors.
Michael A. Hall - Heikkinen Energy Advisors, LLC
A few on my end remaining, I guess. First, I didn't realize that Codell wells -- are those generally spread out consistently with the rest of the program?
Or are they kind of biased towards the inner or the middle? Just trying to think through that.
Is there a material oil mix variablity or GOR variablity within the Codell across the footprint?
Barton R. Brookman
The Codell wells are probably pretty much evenly distributed across the field with our acreage. So really, you're looking at -- if you're looking at our acreage picture, you're looking at the distribution of Niobrara and Codell probably somewhat evenly there.
In terms of...
Michael A. Hall - Heikkinen Energy Advisors, LLC
In the program for '15 as well though. That's what I was...
Barton R. Brookman
Yes, we're really looking at -- as I've said before, about a 65% -- 63% to 65% mix with Niobrara's with 35% Codell's. When you look at the GOR across the field, the GOR does vary from the outer edge.
And I want to say something around 2,000 GOR to the center core -- the center of the core of the field is something 30,000 GOR. And it's fairly rated across that range from the outer edge to that very center of the field.
And the Codell and Niobrara both vary across that distance.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Okay, that's helpful. And I guess you all seem to allude to the potential for additional cost savings as well.
Just wondering if you could quantify that at all or if you've gone back to your share of providers asking for more and how much.
Barton R. Brookman
We're still in the process, I think, of the first pass-through, Michael. I think we're probably, I don't know, maybe 80% or so through our different suppliers.
And it's a significant number of suppliers when you get down to the full spectrum that we use. As far as additional cost, I'm not really sure how much more we'll see.
I also think that it will be a lot of function of what our peer companies do. If we see a significant number of rigs laying down out here, we'll see more downward pressure.
And that's just the supply-demand equation. And how much that is, we don't know.
But that's something that we would expect to see and aren't there yet. And like I said in my comments, we're still waiting to see what many of our peer companies are doing up here in terms of their budgets.
So we still have all that in the future with the plans we have right now, we've settled in. And we're really seeing the 16% reduction today.
And whatever comes over the next several weeks to several months would be an addition to that.
Operator
Our next question comes from the line of Mike Scialla with Stifel.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Maybe just follow on to Michael's question on the $3.6 million well cost. Just to clarify, it sounds like all of that is really based on the efficiency gains that you're seeing.
You really haven't baked in any lower cost from your vendor in that and also any change in the completion style comparing the $4.2 million to the $3.6 million.
Barton R. Brookman
A couple of comments there on the $3.6 million. First of all, it does include our efficiencies that we've been working on as well as the cost reductions, that 16% or so that we've already been in, Mike.
So that's built into the $3.6 million. When you start talking about the differences in the completion methodologies, the main difference between the $4.3 million and the $3.6 million is almost purely cost reductions associated with product prices dropping down.
We really haven't changed our methodologies. We're doing a number of different tests.
And we'll probably repeat most of what I talked about in terms of the sliding sleeve versus plug-and-perf, the additional work that we're doing on the variations in our fluids. And obviously, we've got some additional downspacing work we're doing.
All of those don't really change our cost structure all that much, at least from what we sit today. So really looking at the $3.6 million was primarily a reduction in prices that we've seen as the capital cost -- I'm sorry, as the drilling pace comes down out here.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Got it. Okay.
And then the 580,000 Boe inner core type curve that -- based on just PDC wells at this point? Or are competitor wells figured into that type curve?
And how many I guess wells are in that data set?
Lance A. Lauck
This is Lance. I don't know if I've got the exact number of wells in the total data set.
But the 580,000 is based upon PDC performance as well as industry performance. So our reservoir teams have done lot of work specifically targeting that inner core area and based upon that, may be increased from the 500,000 to the 580,000 that you see here.
So it includes, clearly, more wells than just what PDC has drilled to date.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Okay. Last one.
Just on the differential for the DJ you mentioned, it's around $10. Is that a good long-term expectation?
Or any relief in sight for that to narrow over time?
Barton R. Brookman
No, Mike. From where we sit today, we still believe that the $10 per barrel is a good, long-term differential for crude pricing here in the DJ Basin.
Once again, that's NYMEX all the way back to the tank batteries, so it includes all the transportations and everything associated with that. What we're finding is as time goes by with the additional pipelines are coming to the area, for instance, the Tallgrass line as well as the expansion of White Cliffs, there are better prices on those pipelines.
So maybe over time, that could lead to some tightening on the differential a little bit. But from where we sit, we just -- we stick wit the $10 per barrel differential for crude oil.
And that's what you'll see in all of our type curve rates of return that you see in the presentation today and in our Investor Relations presentations.
Operator
[Operator Instructions] Our next question comes from the line of Ben Wyatt with Stephens.
Ben Wyatt - Stephens Inc., Research Division
Just a quick question maybe hopping over to the Utica. You guys mentioned cost reductions could get you excited and may be doing some work over there.
Can you guys maybe frame up kind of how infrastructure's playing out? How pricing is shaking out over in the Utica and if that's still an obstacle at all for you guys?
Lance A. Lauck
So Ben, this is Lance. So from an infrastructure standpoint, I think we've seen significant improvements in the overall area.
For example, MarkWest has a substantial position there as well as Blue Racer, and both of those 2 companies are continuing to build infrastructure. They're continuing to build out the big gas plants that they have in the Utica area itself.
So we feel very comfortable with the infrastructure and the growth that we see from the Utica within the various play areas. We continue to look at the differentials that we see.
For example, as we look at 2015, natural gas differential, we're using about $1 deduct for TETCO-M2 just to give you an idea of how we sort of think about the world here with that. That compares to CIG back here, where we have in Wattenberg.
And the majority of our gas production, that's sort of the $0.25 to $0.30 per Mcf. So the differential is much better in the Wattenberg.
But I would just want to make it clear that there is substantial infrastructure that continues to grow in the Utica to gather, process and fractionate the NGLs. And then additionally, the condensate in Utica has substantial markets as well, so several buyers for the crude oil condensate coming out of those areas.
Ben Wyatt - Stephens Inc., Research Division
That's helpful. And then maybe hopping back over to the Wattenberg.
Another -- there's plenty to do for you guys with between Niobrara and Codell but just curious if you guys kind of debate internally or doing any work on maybe prospectivity of Greenhorn and core Wattenberg?
Scott J. Reasoner
Ben, this is Scott. We're constantly looking at that.
We are very busy right now and very focused on our Codell and Niobrara and the Wattenberg. I think our plans are to continue to look at that.
We're studying it, and in fact, continue to talk about that as we speak. We hear of our competitors going out there and actually getting active.
We're hopeful they're very successful. That would be a tremendous add to our portfolio if they are.
And we are probably going to be somewhat more followers than we are leaders in that perspective at this point, although we may dabble in a little bit as we go into the future.
Operator
And with no further questions in the queue, I would like to turn the call over to Mr. Brookman for closing remarks.
Barton R. Brookman
Thank you, Nicholas, And then just say, thank you to everyone. Thank you for the support, and I appreciate you joining us for our call.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program.
And you may all disconnect. Have a good day, everyone.