PDC Energy, Inc. (NASDAQ:PDCE)
Q4 2015 Results Earnings Conference Call
February 22, 2016, 11:00 AM ET
Michael Edwards - Senior Director of IR
Bart Brookman - President & CEO
Gysle Shellum - CFO
Scott Reasoner - SVP of Operations
Lance Lauck - EVP
Mike Kelly - Seaport Global Securities
David Tameron - Wells Fargo
Pavan Hoskote - Goldman Sachs
Brian Corales - Howard Weil
Brad Carpenter - Cantor Fitzgerald
Dan McSpirit - BMO Capital Markets
Michael Hall - Heikkinen Energy Advisors
Welles Fitz - Johnson Rice
Ryan Oatman - Cowen and Company
Ipsit Mohanty - GMP Securities
Neal Dingmann - SunTrust Robinson Humphrey
Irene Haas - Wunderlich Securities
Paul Grigel - Macquarie
Jason Smith - BofA Merrill Lynch
Mike Scialla - Stifel
Michael Glick - JPMorgan
David Beard - Coker & Palmer
Jeffrey Campbell - Tuohy Brothers
Good day, ladies and gentlemen and welcome to the PDC Energy 2015 Fourth Quarter Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference call is being recorded.
I would now like to introduce your host for today's conference Mr. Mike Edwards, Senior Director of Investor Relations. Sir, you may begin.
Good morning, everyone, and welcome. On the call this morning, we have Bart Brookman, President and CEO; Gysle Shellum, CFO; Lance Lauck, Executive Vice President; and Scott Reasoner, Senior Vice President, Operations. We've posted a slide presentation that accompanies our remarks today on the Investor Relations page of our website, which is pdce.com.
I'd like to call your attention to the 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 where you'll find the reconciliation of non-GAAP financial measures. With that, we can get started and I'll like to turn the call over to Bart Brookman, our CEO. Bart?
Thank you, Mike, and welcome, everyone. This has been quite an eventful year and yet we're extremely pleased with our 2015 results. We enter '16 in a very strong position, both financially and operationally, but recognize the severity of this market correction and the challenges it brings,
In 2016, the company's focus will continue to be intense focus on balance sheet management, cash flow neutrality with ample liquidity. Growth in '16 and 2017 driven by balance sheet strength, executing on our value-add drilling programs, improving our cost structure and deducts to help drive additional margins and last, continually striving to maintain quality, environmental, health and safety programs.
Let me cover some of the '15 highlights. Our annual production grew to 15.4 million barrels equivalent. That is a 65% improvement from 2014 levels. We recently announced our proved reserves, 273 million barrels equivalent. That is a 9% increase from yearend 2014 levels and a 247% reserve replacement level for the company.
Our lifting cost increased approximately 20% year-over-year to 371 a barrel, a tremendous accomplishment on part of our operating teams, particularly in an environment of ever increasing regulatory cost and last, we greatly improved our EH&S statistics, a combined effort of our EH&S and operating teams.
From a financial perspective, our yearend 2015 debt to EBITDAX, we exited the year at approximately 1.4. The liquidity of the company at yearend was approximately $650 million.
Our debt-to-cap was 33%. We had $420 million of adjusted cash flow from operations that is a 68% increase over 2014 levels. And very important in our August re-guide last year we committed to manage the company in a cash flow neutral position. I’m proud to report we achieved cash flow positive for the second half of 2015.
Now let me update everybody on 2016, last December we released our plan to spend approximately $475 million in 2016 and produced 21 million barrels of oil equivalent. We are also focused on cash flow neutrality, all while maintaining full operational flexibility should the market continue to deteriorate.
So where do we stand today and philosophically where we are going? Our CapEx based on the original December drilling plan is now $435 million. This is a $40 million improvement from the December announcement and is based solely on a continued decrease in our per well cost in the Wattenberg Field.
Production expectations remain at 21 million barrels equivalent and we continue to maintain full operational flexibility including the option of slowing down activity should market conditions persist.
In an effort to stay cash flow neutral, we will keep monitoring several factors. First and foremost commodity prices, both oil and natural gas. Next ongoing improvements in our capital cost per well particularly in the Wattenberg Field and in the Wattenberg our drill times and oil deducts continue to improve and several technical innovations are providing early production data and Scott will give more detail on several of these factors in a movement.
We feel fortunate to have this kind of operational flexibility, given our acreage is held by production and our rate contracts are short term. So in closing I would like to thank all of the PDC employees for their efforts in 2015. These individuals are a key reason the company is so well positioned to weather this storm and continue on with our resilient business plan.
And with that I will turn the call over to Gysle for some financial details.
Thanks, Bart. Good morning everyone and thanks for joining us this morning.
We filed our Form 10-K and our fourth quarter earnings release this morning. My comments today will be in summary form. Please see those two filings for more detailed description of the performance for the quarter and year.
As you've heard we had tremendous results in 2015 in Wattenberg as well as steady production from our Utica operations. Production from the fourth quarter was 4.8 million barrels of oil equivalent, which was above our expectations and led to our full year production of 15.4 million Boe, solidly beating the high end of our guidance.
Our fourth quarter reflects continued success of the Wattenberg program, which again had record production as well as the Utica wells performing in line with our expectations.
Despite much lower commodity prices, we still had substantial growth year-over-year in adjusted cash flow from operations and adjusted EBITDA aided by our hedge position with $76 million in realized hedge gains in the fourth quarter and $239 million for the full year 2015.
With the high level summary now, let’s get into some of the metrics for the fourth quarter on Slide 7, starting with oil and gas sales, again this quarter year-over-year production increased over 85% while our fourth quarter total sales of oil and gas was only up 3% compared to the fourth quarter of '14. Oil and all commodity prices declined year-over-year and quarter-over-quarter.
Crude oil for the fourth quarter of 2015 averaged $35.26 down 42% from the fourth quarter of 2014. Average natural gas prices were down 48% from the fourth quarter of 2014 and natural gas liquids were also down 48%. For the full year prices were down 50%, 47% and 61% for oil, natural gas and NGLs.
When we factor in our hedges however, total sales plus realized hedges were up approximately 49% over the same periods. For the full year, combined realized hedges and total sales were up 32% from 2014.
Our net realized hedge gain of $76.5 million this quarter compares to a net realized gain of $20.7 million in the fourth quarter of '14 and a net gain of $68 million in the third quarter of last year 2015.
For the full year, net realized settlements were $239 million compared to a net realized loss of $2 million in the year 2014. Production cost on a per unit measure were down 19% year-over-year. Production cost include lease operating expense, production taxes, transportation, gathering and processing.
I do want to mention in our press release, we went into detail on how we've reclassified production cost and G&A. While total expenses have not changed, the reclassification is intended to better align our cost with how peers report LOE and production cost.
For the fourth quarter of 2015, we've averaged $4.81 per barrel oil equivalent down from $5.92 per Boe compared to the same quarter last year. For the full year, our production costs were down 29% from $5.57 per Boe from $7.81 for the full year 2014.
Gross margins which don’t include hedge settlements were 78% of sales for the fourth quarter 2015, down slightly compared to 85% for the fourth quarter 2014 reflecting the big increase in commodity prices -- big decrease in commodity prices nearly offset by a strong decrease per Boe in total production cost. For the full year, the gross margin was 77% down from 85% for the fiscal year 2014.
Moving to Slide 8, we show our non-GAAP metrics and I want to mention you can find our reconciliation in the appendix. Our adjusted net income of $12 million in the fourth quarter compares to $40 million adjusted net loss for the same quarter 2014.
For the full year, we had an adjusted net loss of $46.1 million compared to a $37.7 million adjusted net loss in the year 2014. I will talk more about that in a minute.
Cash flow from operations is defined as cash flow from ops excluding changes in working capital. Adjusted cash flow for the fourth quarter was $127.2 million or $3.08 per diluted share compared to $70 million or $1.94 per diluted share for the fourth quarter 2014.
For the full year, adjusted cash flow from operations was $420.8 million or $10.75 per diluted share compared to $250.2 million or $6.82 per diluted share for the year 2014.
Adjusted EBITDA in the fourth quarter was $129.1 million down compared to fourth quarter of 2014 of $161.2 million. Adjusted EBITDA in the fourth quarter of 2014 includes $76.4 million in gain on sale of our Marcellus joint venture properties.
For the full year adjusted EBITDA was up 22% to $443.2 million from $364.3 million for the year 2014. Adjusted EBITDA per diluted share of $3.13 was down from $4.46 in the fourth quarter of '14. For the full year 2015 it was up to $11.32 from $9.93 for the year '14.
DD&A includes depreciation of fixed assets and depletion of oil and gas properties. Per unit DD&A rates were up slightly in the fourth quarter of 2015 to $20.16 from $19.52 in the fourth quarter of '14.
For the full year per Boe rates dropped slightly to $19.73 from $20.71 for 2014. At the bottom of the slide, we show adjusted net income excluding impairments. When we adjust for Utica impairments of $150.3 million in the third quarter 2015 and $158.3 million in the fourth quarter 2014, we would have net income of $44.2 million for the full year 2015, compared to $59.5 million for the full year 2014. Adjusted net income in 2014 includes the after-tax gain on the sale of the Marcellus joint venture properties of approximately $49 million.
G&A decreased 28% on a per unit basis to $5.83 per Boe in the fourth quarter and $8.13 per Boe in the fourth quarter 2014. For the full year, G&A per Boe was $5.86 compared to $8.96 for the full year 2014 after excluding one-time litigation charge of $40.3 million in 2014.
Moving to Slide 9, table reflects PDC's borrowings. Our borrowing base was reaffirmed at $700 million in the fall and we kept our commitment to $450 million. We were cash flow neutral again in the fourth quarter and exited the year down -- drawn $37 million down from $50 million at yearend in Q3 2015.
Our debt to EBITDAX at yearend was approximately 1.4 times as Bart mentioned with a borrowing base of $700 million, net of $12 million letter of credit, we have approximately $652 million of liquidity at yearend, a $115 million convertible notes mature in May of 2016.
We plan to retire the face amount in cash and use common stock for anything above the $42.40 convert price.
Lastly, our bonds maturing in 2022 were confirmed at B-plus rating at S&P recently. We've not heard from Moody's yet who is also undergoing review of high yield in the NP sector.
The last slide shows our hedge positions. Our hedges for 2016, '17, '18 are shown here as of February 15. Our net hedge value at that date was $263 million. We have substantial hedges in place for 2016 with approximately 52% of our oil volumes protected at $81 per barrel and approximately 62% of our natural gas volumes protected at $3.65 per MMBtu.
In 2017 we've doubled the volumes hedged since the beginning of the year and now have approximately 3 million barrels hedged at an average floor of $48 a barrel.
Our natural gas, on a natural gas side, we added some volumes in 2017 and now have 32.5 Bcf equivalent hedged at $3.51. In 2018, we have about 18.7 Bcf hedged in the low $3 per Mcf. We plan on providing detailed financial guidance at our Analyst Day in April, instead of on the call today.
Now I'll turn the call over to Scott, for a discussion on operations.
Thank you, Gysle and good morning, everyone.
As both Bart and Gysle mentioned, we're very pleased with both the fourth quarter and full year 2015 results. production for continuing operations for the year averaged just over 42,000 barrels of oil equivalent per day and totaled 15.4 million barrels of oil equivalent, a 65% increase over 2014.
On Slide 13, you can see several highlights of our 2015 program. Our commodity mix was 45% oil and 64% liquids. Fourth quarter production increased 11% sequentially and had a December exit rate of just under 52,000 barrels of oil equivalent per day, an increase of approximately 85% over the 2014 rate.
As Gysle and our earnings release this morning touched on, we've simplified the way our production cost are now calculated. This resulted in some minor reclassifications to various areas including LOE.
The graph on the bottom right shows the tremendous strides we've made in reducing our lifting cost over the last couple of years. All of these values have been recalculated as a result of the recent accounting changes and you can see that even with the adjustments, our full year LOE of $3.71 came in at the bottom of our 2015 range. Year-over-year, LOE decreased nearly 20%, a real accomplishment by our operating teams.
2015 yearend reserves came in at 273 million barrels of oil equivalent, a 9% increase over yearend 2014. Our proved developed reserves as of yearend 2015 were 71 million barrels of oil equivalent, down slightly from 75 million barrels of oil equivalent at yearend 2014.
Our yearend 2015 proved developed reserves would have increased to approximately 90 million barrels, but two factors reduced them. First, the company lost 8 million barrels of proved developed producing reserves due to the low SEC price deck and second, we wrote off our proved developed reserves related to our vertical re-frac program that is no longer in our five-year plan.
Lastly, proved undeveloped Wattenberg locations totaled 790, a result of not only high-grading our portfolio to the metal core, but increasing the spacing density of proved reserves from 8 to 16 Niobrara wells per section equivalent.
Next on Slide 15, you can see the results in terms of wells spud and turned in line in 2015 as well as the estimated 2016 numbers. In the fourth quarter, we spud 44 gross wells, all of which were standard reach laterals and turned in line 43 gross operated wells.
As a reminder, our plan is to spud approximately 135 Wattenberg wells in 2016. These wells will be approximately 130 each of standard, mid and extended reach laterals. We expect to turn in line between 165 and 170 wells in 2016 as shown on the graph.
CapEx for the year came in at $559 million, slightly above our expectations as a result of higher working interest and increased non-operated activity in the second half of 2015. We continue to monitor closely these trends and their potential impact on our 2016 plan, but so far in 2016, we've not been seeing the same scenario.
I'll also note that similar to the third quarter, our cash flows from operations exceeded our capital expenditures and we were able to slightly pay down our revolver.
For 2016, our updated capital forecast has been reduced by $40 million at the midpoint as a result of the well cost savings we've realized thus far. As it stands, our standard, mid and extended reach lateral wells including plug-and-perf are coming in $2.6 million, $3.6 million and $4.6 million all in and we continue to see downward pressure on these costs.
For comparison sake, these costs are 20% to 30% lower than our SRL and MRL cost of $3.6 million and $4.6 million we were discussing on this call last year.
Moving to Slide 17, we show here our middle core Niobrara internal rates of return and PV10 for both standard and mid reached laterals after considering the improvements in both well cost and basin oil differentials.
We elected to exclude our extended reach laterals from this slide for now as we've yet to begin drilling these wells and are planning on doing a deep dive into the details at our upcoming Analyst Day in April.
Due to price fluctuations and to give a sense of the effect of your pricing has on our returns we ran these economics at both strip pricing and a Bloomberg consensus deck. I won't read through the numbers at this time, but you can see that at recent strip pricing, both standard and mid reach lateral wells delivered solid rates of return that more than doubled our weighted average cost of capital.
Standard reach lateral wells have a slightly higher internal rate of return and mid reach laterals due to lower cost and similar IP rates. However, you can see that the PV10 of a mid reach lateral is higher.
We consider both internal rates of return and PV10s when making drilling decisions as well as permits, lease holdings, surface impact and a variety of other factors. All in all, the message here is very simple. We make drilling decisions based on un-hedged economics that are still very reasonable, even in the current price environment.
Now moving to Slide 18, I'll briefly touch on some of the key 2016 initiatives and a midstream update. As I mentioned previously, we plan to drill our first XRO wells of approximately two miles later this year. Industry data certainly seems to be pointing in the direction of longer laterals and we will keep you posted on our results as they come in, but again this is the second half event with results most likely in the 2017 timeframe.
We’ve gained enough confidence in monoboard drilling to shift our standard in mid reach lateral wells to this method and will target to do the same with our XRO wells after successfully completing a few in the traditional method. So far monoboard drilling is saving up to one day in our drill times and we're confident that we can improve on this number.
As we mentioned in our December press release aside from a few carryover slightly sleeve wells, we’ve shifted our entire Wattenberg program to include plug-and-perf completions and are now testing the additive effect that excess frac has on these wells. We have completed several of these wells to date but it's still a little early to comment on results.
From a midstream perspective, DCPs Grand Parkway did a great job piggybacking on those certain two project from last year and we continue to see favorable line pressures throughout the basin.
Also of note earlier this year, we begin piping oil directly from the well head on the Saddle Butte System. We're excited in this developments as it leads directly to reduce truck traffic and well side emissions and other environmental benefits.
As we have in the past our in-depth technical update at Analyst Day in April we'll cover many of our test results in much greater detail. Again a brief technical update to go through on Slide 19.
You can see that our down spacing in mid reach lateral project at Chestnut Pad continues to track our 600,000 Boe type curve as our plug-and-perf wells on the standard reach laterals continued to outperform the slighting sleeve wells.
As a reminder up to 15% production improvements related to plug-and-perf technology was included in our 2016 production guidance and the cost associated with plug-and-perf is included in our current well costs.
We are still in the data gathering phase on our 22 and 26 well equivalent down spacing tests as well as plug-and-perf with access frac. Look for updates on these results in the very near future as well
In the Utica we plan to spend approximately $35 million in 2016 to drill and turn in line five wells. In the southern part of our acreage we will drill the two well Mason pad using the same successful completion methods used on the coal and dynamite pads.
The two Miley wells are designated to test well orientation as both laterals will be drilled slightly west of north. Both the Masons and the Mileys will have approximately 6,000 to 7,000 foot laterals similar to those of the coal and dynamite.
Finally, the Neff well is located in between the coal and dynamite pads and we'll test the efficiencies of increased lateral length as it will have a 10,000 foot lateral. We're currently projecting well cost of approximately $6.5 million for a 6,000 foot lateral well, down from nearly $9 million at this time last year with some downward pressure still potentially pushing these lower.
Our 2016 Utica program has an eye on 2017 as we will be faced with lease extension decisions at that time. Lastly, our overview slide gives you some of the more granular details such as Niobrara versus Codell turn in lines and horizontal versus Niobrara production that I will let you get into on your own.
With that, I'll turn the call back over the moderator for Q&A.
[Operator Instructions] Our first question comes from the line of Mike Kelly with Seaport Global Securities. Your line is open.
Thanks, good morning guys. First question I guess would be for Scott, kind of following on the efficiency gain comments and I’m curious this might be something you want to save for Analyst Day, but in the upside case scenario where both the monoboard work and also you get an incremental uptake from access fracs, where do you think you could take those returns on Page 17 that kind of both those scenarios working everything else held constant. Thanks.
And I guess that the best answer to that is that we’re still looking at that. Obviously the monobaord is a time savings process and I still think the cost per day when you're all and including the cost of the drilling rig and all -- and services that go along with that are in that $50,000 a day range.
So I would say that's the best estimate of the cost reduction associated with that. If you talk about access frac that 5% to 10% incremental production is really what we're still looking for and I will say that that is -- it’s going to be a little harder to see when you start doing with that plug-and-purf wells because the range on the plug-and-purf wells is still fairly broad when we talk that 15% to 25% range you can see 5% to 10% in that -- mixed in with that from the access frac makes it more difficult to see the real benefit.
So we will probably have to do more testing on the access frac combined with plug and perfs that we did with it on its own. But as far as the rates of return it’s really tough for me to say without knowing the outcome of that, but obviously we’re looking to do that so that we can continue to improve on our rates of return and continue to see cost come down and the production improvement you guys are all aware of that we've seen thus far.
Okay. Great. And switching gears for Bart or Gysle was just hoping to get some color on the liquidity front and really curious your expectations for the spring borrowing base termination season here?
And just your general comfort level and maybe your strategy to keep liquidity ample with the converts coming due in May and then also your hedge book in '16 which is great, kind of rolling off and not being as robust into 2017. Thanks.
Yes Mike, this is Gysle. I'll try to address some of this, obviously we don’t know what the banks are going to come up with in the spring. Their price decks now are down from the fall as I’m sure everybody knows, but they're probably not final.
We did add a lot of reserves this year albeit at lower prices. So I’m not going to predict where we will end up with our borrowing base in the fall. It's just too early to tell and too many variables out there with prices still moving around.
I will say that with where we're drawn now and even with the draw to retire the convertible bonds, we expect it will be under $200 million drawn and I don’t see us losing a lot on our borrowing base to the point where we would be stressed at that level.
And we can maintain cash flow neutral in 2016 to not grow that borrowings throughout the year. And then with respect to 2017 hedges yes, we're less hedged in 2017 than we've been in the last few years. The fat lady hasn’t sung on that yet. There are still maybe some opportunities to get some decent hedges for 2017.
As I mentioned we doubled our position in oil hedges in '17 in the last two months. We've been picking up opportunities at an average price of roughly $48. I hope we'll lost money on those hedges. It will be -- we'll be really hopefully be adding some more for that year when we see opportunities.
I feel pretty comfortable with our liquidity position obviously throughout 2016 and through 2017 we've modeled internally at ad nauseam low prices through 2017 and we show that we can continue operating at a possibly a lower pace, but still operate pretty close to cash flow neutral for those periods.
Thank you. Our next question comes from the line of David Tameron with Wells Fargo. Your line is open.
And I don’t know, maybe you said this and I missed it, but as far as well cost go, just a decrease since you're into that, is that all service cost reductions or what's driving that because we've seen that from a number of producers that have some good core acreage?
David I think when you look at that, it’s a combination really of the efficiency from the drilling process. We've seen a little bit of continued improvement there maybe a half a day that kind of number.
So that's a small amount of it. The remainder of it is really a broad cross section of the service entities of providing lower prices and it's very competitive out there as you can imagine with that 400 rig count kind of looking square -- as square in the face.
There is a lot of excess capacity and so really we're still seeing that downward pressure and it sometimes surprises me. I am pleased that we're able to keep the prices coming down because it does make our economics that much more favorable and if you look at it on any one category, our teams are working across all the different services on a fairly consistent basis and staying in close touch with the service companies to get those cost to continue to come down and we still see downward pressure David.
All right. Thanks for that and then as I just think about, you guys are drilling a number of extended reach laterals this year. I guess you're drilling your first this year. How should we think about returns on those versus whatever slide it was 19 I think or 17, where you gave the other two return scenarios. How should we think about that relative to standard and middle?
And I think just from a general perspective and as I said, we'll be looking at that very closely and trying to provide you much clear information when it gets to Analyst Day, but when I look at that, I would say that we'll see a slight downward internal rate of return maybe a few percentage points and obviously an upward PV10 as you increase those lateral lengths.
And the reason for that David is we continue to choke our wells back early in the life of the wells and that somewhat suppresses that rate of return, but obviously doesn’t really affect that PV10 value much.
Thank you. Our next question comes from the line of Pavan Hoskote with Goldman Sachs. Your line is open.
Thank you. Good morning, guys.
Good morning, Pavan.
So Bart in your opening remarks you talked about a focus on commodity prices, cost improvement and cash flow neutrality, but what specifically -- are there any leverage, liquidity or any other metric that you focus on as you decide on whether or not you want to issue equity at these levels?
And similarly are there any metrics that you focus on besides cash flow neutrality as you're trying to decide on the right levels of activity for 2016 and 2017?
Yes, let me jump in here on this and first and foremost as Scott talked about right now, we're looking at different pricing scenarios whether it's strip, when you look at flat pricing, we look at the Bloomberg consensus and we've got an internal forecast and all of those we make sure our drilling programs are adding value. So that's the first step.
Then we roll that into our forecast and right now, our primary driver is that we're coupled with our hedges in '16, managing around the balance sheet and whether that's cash flow neutrality, slightly positive and some scenarios maybe just a little bit of an overspend, but we're really, really targeting that cash flow neutrality.
Pavan, obviously the biggest driver in all of this is commodity prices. So that is the biggest trigger that we look at and we're monitoring it and we do anticipate -- we do anticipate that there will be a rebound at some point in time.
We're not sitting here saying we have the ability to forecast exactly when that will be. We think it's probably towards the end of this year or sometime in '17, but I think we also recognize that there is risk this could go push deep into '17 or potentially '18. So we have those scenarios we also look at.
So bottom line pricing is our first trigger, but Scott as you noted, we've got about three or four other things right now that we've got to get clarity on and the first is the final results of some of the down spacing and access results in the production enhancement from those.
And the second is our final drill times and the drill times are important from a cost per well basis, but also from a pace in the basin and Scott and the operating teams are seeing some very, very positive things there.
And then the final one we just talked about at length is the cost per well. You see what happened just from December to today. We improved our CapEx by $40 million. So when Scott says, there is additional improvement coming through, we're trying to really define all that.
Then we have to roll it all into a bucket and say okay, what kind of returns are we delivering? What's the balance sheet look like? We exited the year at 1.4 debt-to-EBITDA. We feel very good about where we are at on our balance sheet strength and we remodeled and we make decisions around that.
So the timing of all that, I think you can expect over the next couple months, we’re going to be meeting with our Board here in the next month reviewing all of this in detail and making decisions and those will be the right decisions and they will be based on a variety of factors.
Now you’re opening as far as the equity, is that absolutely out? I can never say equity is out, but right now our primary focus is to manage the balance sheet through flexibility and our capital spend and that we believe we can do as we go through 2016.
Got it. That’s a really helpful answer but -- and then on somewhat of unrelated note, last quarter you talked about a 60 well inventory to 2016, can you talk about your willingness to reduce rig count and working through your inventory to improve capital efficiency on a temporary basis and that's more 2017 point.
Yeah we maintain -- we keep that as an option. It is not a primary way right now that we're managing the capital spend, but we recognize -- let me answer this way, if oil were to stay between $25 and $30, as we go through the balance of the year, I think we would use ducks as maybe a way to manage the balance sheet and manage our growth towards the end of '16 and manage our growth in '17 as we try to weather the storm.
But right now, based on what we see and the returns Scott just presented, we're really not in a mode of building completion inventory and it's also an efficiency issue for operating teams. They are really set up with the four rigs to obviously drill the pad out, build the schedule, we're very closely with our completion provider.
And build that schedule and sticking to that schedule is part of the reason we continue to have cost saving pass-throughs from them because we have a reputation for doing what we say and that end up adding some value when you look at the bottom line pricing.
Our next question comes from the line of Brian Corales with Howard Weil. Your line is open.
Hey, guys and Bart maybe this is right to one of your last points on the down spacing, where do you all -- how much more do you need to see and can you may be talk about is there an average -- how many wells per section or the equivalent of that you're drilling in 2016?
Yeah, and this is Scott, Brian. I'll start and Bart may jump in here, but I look at this and our plans for this year primarily focus around the 20 well per section equivalent spacing and that’s a combination at Niobrara and Codell wells and it's a lot of function of the number of wells already in the section, a number of factors that play into that.
In terms of the -- looking at the tests that we're running currently, as you all know, we tend to lean towards a more conservative side, so before we really make decisions, we really like to have a fairly good supporting set of data that puts us there. We’re getting there, the data we're getting is solid. It will help us and I’m hopeful that will have -- it will help us determine what the next steps are and how we approach late 2016, early 2017.
So we see good data. We’ll hopefully have that data at Analyst Day. I’m not a 100% sure because I haven't looked at it in a while. What it will tell us but I think we're there in terms of understanding at least that 22 and 26 well count.
And I again I have to caution everybody about just saying well we go drill 26 wells if it works? The answers is it depends a lot on what the existing well count is. Also the surface issues that we might be faced with. There are a lot of factors that go into how many wells we drill on a section. So that’s the best I can give you at this point, but we are getting good data.
Okay. And then one on plug-and-perf, you’re adding I guess about 15% to production as a result, it seems conservative, is the average what is then the average improvement? Has it been 25 or is it not quite that high?
Yeah, I don’t think it's quite that high Brian. You're really looking at something that’s in that range between 15% and 25% but it's on a limited number of wells in a particular area and its only on our standard reach laterals.
So, the mid reach and the long reach laterals don’t have any of that in them because generally they were drilled with plug-and-perf technology in the first place.
So it’s really the standard reach laterals and has everything to do with -- being early data in limited areas is why you may call it conservative. I think it’s probably realistic for the short term and hopefully we can improve on that over time and I believe our teams will take that to the next step one way or the other either through access frac added to it or better distribution of fluid along a particular stage and by better utilizing the plug-and-perf method.
Our next question comes from the line of Brad Carpenter with Cantor Fitzgerald. Your line is open.
Hey good morning guys. Thanks for the update. Bart, I was hoping to get your thoughts on M&A. You previously mentioned your team is working on an internal basic study that would help frame some of your decisions, but I was curious given the additional downtick in commodity prices from the third quarter call, how should we think about your appetite for potential acquisitions outside of the DJ?
I’m going to let Lance jump on this one.
Yes so how we see the world with that is that we have such a substantial inventory of projects in the Wattenberg Field that we organically can grow for many, many years to come.
We continue to do our basin study work and look for other basins and core areas outside of the Wattenberg area, but keep in mind we're very patient. We're very methodical. It's very much an engineering, geological driven type of analysis and it’s really just our normal course of analysis that we do as an ongoing basis.
So yes, we’ve seen prices come down recently, commodity prices. I think what it may do more than anything is just make it even more difficult really at this particular time to pursue an acquisition because it’s getting harder and harder to get other assets to compete with what we have in the Wattenberg Field.
So we're very fortunate to have such a tremendous asset, tremendous people that really know and understand this basin of work in the DJ for a long period of time.
So we feel very comfortable where we are today. We will continue to monitor the AND market that's part of our business plan. It's part of our long range plan that we look at, but our focus is really on the organic side of what we have.
Brad, the only thing I would add on that like Lance said is we'll continue to monitor. I think we have probably seen increased deal flow here the last few months. We're a little bit surprised that the bid ask has stayed as wide as it has and I think with this first quarter correction in pricing you're going to see that the paint start rolling through the market and that's going to really start narrowing.
So maybe that will improve some opportunities, but right now as Lance said, we're being incredibly finicky about what we’re looking at.
Okay. Great. That's helpful and then I guess staying with the theme of the solid returns in the Wattenberg part or maybe this one is for Scott whoever wants to take it, your team has done an impressive job of proving well results, coming out of the field over the last handful of quarters and I was wondering are we at the point where you're essentially blurring or even removing the bright line between the middle and intercourse that you draw on your map at least from a well return standpoint?
It is very hard to answer that question. I would say the best way for me to describe it is as we move any part of it up we believe it moves the entire field up. So the plug-and-perf operations we've tested it in a little area, but we believe that will layer over on to the other areas and until we see differently that's what our expectations are.
And so as you move from the middle core to the inner core or the middle core to the outer core, we expect those same kind of increases and if we’re not getting them we want to understand why and make some changes so that we can continue to improve on that.
When you look at our middle core inventory, it’s large. Our inner core inventory is getting smaller and to the point where we’re really not relying on it much anymore, we’ll have some wells in that area, but they’ll be limited and they’ll be infrequent.
And so we’re really looking at the middle core as our primary focus and I think is it such -- we're blurring the line between them a little bit I would say, but it really comes down to -- we're really raising all of the rates of return up with the lower cost and with the plug-and-perf type technology.
Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Your line is open.
Thank you and good morning folks. Can you speak to how the company’s acreage is set up for external wells that is how much acreage can be drilled with the XRO and/or how much inventory can be converted under that assumption on lateral length.
I ask that question in the context of that waiting to SRL wells and drilling activity this year and last year and whether that waiting will change or may be change meaningfully in the periods ahead.
I think when you look at our acreage, a large portion of it is not set up to do the extended reach laterals. We continue to try to improve on that situation, but the mid reach laterals and the standard laterals will be more of our standard.
As we look at these, obviously there is an opportunity to drill all of the wells at that two mile length, but we just end up including other people's interest in our wells and those -- that discussion with those other companies, they tend to want to operate their own wells as we do.
And I think when you look at the benefits of it they’re not all that great. When you look at the rate of return PV10s it's such that we’re more efficient obviously, but not to the point where it's worth really pushing north other companies to try to get deals done.
So I would say this year is a third, a third, a third and next year I don’t have a full plan, but I wouldn’t expect it to be quite as many extended -- of the extended reach laterals.
Great, thank you. And as a follow-up how does the product stream change on a typical middle core horizontal producer specifically the oil cut say in the first three years of that well's life?
No and we have a slide on that Dan that we’ve shown in the past and I think is it in our Analyst Day Mike?
Last year's Analyst Day.
Last year's Analyst Day shows very specifically how those wells change over time and about 18 months, 24 months we really see that geo stabilize and so Mike has landed here, Mike Edwards has landed that here in front of me, but it gives the best indication of what we expect over time in both interim middle core as well as the outer core.
Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Your line is open.
Thank you. Good morning,
Good morning, Michael.
Just wanted to I guess follow on a little bit on a question from earlier around just your sensitivity to current pricing relative to your activity profile and I was curious on Slide 17 are those returns at the field level or are those at full cycle, fully burdened planned and hook up etcetera?
Front line level including all deducts and all call it direct cost to the AFE.
Could the equipment, the drilling and completion and as Bart said net back to the well head prices.
And so at what price like in the current environment, where we can have a 20% return-ish on a full corporate basis I imagine that’s still clearing the full cost, but getting close there. At what point do you -- at what price do you budge and reduce your activity profile?
Again it's not specifically just a price Michael, it’s a combination of price plus anything Scott and his teams can squeeze out of this cost structure. Its monoboard drilling in the times and how that improves capital efficiency.
It's some of these continual production enhancements that we have and so we've really got to throw all that together along with the Lance and our marketing team continue to make strides in our deducts.
So we’ve got all of these factors and its why we don’t want to over react and as I said earlier, we still believe there is a rebound. I can tell you this so, if oil stays with the two handle on it, we recognize we’re going to be heading towards the second half of this year. Our hedges will be rolling off. We've got tremendous production growth and we will probably give some consideration to slowing down if we feel like the pricing market is going to stay really, really, really bad into 2017.
We will not lose focus on our commitment to manage around the balance sheet. So, now I just gave a lot of what if scenarios and as I said in my opening, the blessing for the company is that we have held by production acreage.
We have short term contracts in our rigs and we can move pretty quick and I should know, we can move either way pretty quick. We can slow her down or we could speed her up. So hopefully I answered that. So I don’t have an exact on that. But we can give you some just general feel of where we’re at.
Thank you. Our next question comes from the line of Welles Fitz with Johnson Rice. Your line is open.
Hey guys. Good morning.
Scott, you hit on this a bit but any specific update on the reader pad and if your location count does jump up to that 26, how does that change the way that you think about kind of a hurdle rate for M&A given that your number of locations is obviously going to be much higher?
I will speak to the Reader and then hopefully Lance can give you some more direction on where we go on the M&A side. I guess Welles the best way to say it at this point is I haven’t looked at that Reader project in a couple of months.
The data is such that it’s good quality data. We’re seeing what we want to see and in terms of what the outcome is as you all know the real truth in the data is the longer term look at that because it’s generally not in the first 45, 60, 90 days that you see the impact. It's generally a little longer period of time.
So I guess the thing that we’re trying to do is make sure we’re assessing that data very clearly and comfortably that we understand what we got there and again I’m hopefully that we will be looking at that data at Analyst Day if it’s something that looks to us like it's worth spending time on obviously because that's part of what our decision is all the time.
How do we allocate our time and one of those conversation that goes on quite some time there typical Analyst Day. So it really comes down to that, but I don’t have a good update for you at this point really looking toward Analyst Day to hopefully do that.
And Wells, this is what I would add to that. When you look at our inventory Scott highlighted earlier, it's based on 20 horizontal wells per section. Obviously any additional work that's done over time to show additional downspacing will have a positive impact on the inventory count.
So as we think about that, I think it gets back to the fact that we're very fortunate to have such a tremendous field in the Wattenberg core area because it’s a tremendous organic growth profile for many, many years to come.
So we have a top tier asset, one of what we believe to be the very best in the U.S. onshore and that positions us to be in a place where we can drive a lot of value with the assets we currently have.
Okay. Perfect and then one quick last one, it looks like the Utica acreage count dropped by call it 2K, is there just some non-core stuff that you guys didn’t want to renew?
Yes we're being very selective Welles even going into the future as we test these wells. We're going to be very selective about the acreage that we extend and so as we get some of the fringier acreage that decision is fairly easy. We're not going to extend it.
What we hope to learn with the drilling program that we have this year is what portion of that do we want to extend that's expiring in 2017 and it really is a question that we need to answer.
The wells are such they will help us understand that as well as some of the other technical things that I pointed to the longer laterals, the drilling slightly off north there is something that we've heard in the industry has been generating better wells and we've been drilling most of our wells just north south.
So with that we'll make better decisions hopefully come 2017 when I think we've talked in the order of about $30 million worth of renewals if we extend it and that's a big if, if we extended at all with that acreage that's expiring.
Our next question comes from the line of Ryan Oatman with Cowen and Company. Your line is open.
Hi, good morning and thanks for taking my questions. You answered where I was going to go with this Utica asset, how you're thinking about it conceptually. So want to see if we can drill down a little bit into 2016.
Gysle, I know you talked about additional guidance at the Analyst Day, but in December you all talked about the capital budget being weighted towards the first half of 2016. Just want to see if you all can provide some additional detail as to how we should be thinking about that? What we should be modeling at this point?
Yes I think, this is Gysle, for 2016 we did reduce as you noticed our CapEx, but still it's frontend loaded and that's on the maintenance program that we mentioned in December with four wells running through the full year.
Now if we change that because of economic conditions of pricing and it would likely affect the last half of the year and not the first half of the year, Scott have you anything to add.
Yeah, I can add a little bit to that I guess when you look at that 60 count approximately that we carried in, we started with our second frac crew at the beginning of this year and that’s really what the frontend loading is based on.
We’re running two frac crews right now and again it's something that we had planned all along really to approach it this way. So that’s really what’s frontend loading that with two thirds of the total well cost being completions you can see how that would drive that early time capital in the first part of this year?
Got it, that makes sense, with the implication being that second curve will drop sometime later this year?
Yeah, at this point it's scheduled for -- sometimes second quarter is really what our teams I think have it scheduled out at this point.
Got you and then one last one for me with overhead and other production expenses being reclassified to G&A Gysle can you speak to what run rate G&A we should be looking out for 2016 and cash and non-cash components if you have those as well?
We haven’t nailed that down yet Ryan. I’m going to have to defer till we give financial guidance, which will be at the Analyst Day?
Thank you. Our next question comes from the line of Ipsit Mohanty with GMP Securities. Your line is open.
Yeah, hey good morning guys. Just looking at Slide 17 wonder how those numbers would change or trend if Niobrara is replaced by Codell. So in other words your decision to going Codell development would it be -- would it change at all based on these returns are will be more of the drainage and all those other geology issues?
I think when you look at it, obviously when we move into an area if we're drilling, we want to drill all the wells that we think are appropriate at the time, the pad preparation, the equipment preparation for all that is important.
So what we look at Ipsit when we make that decision, obviously those economics become critical and the Codell wells do come on with a little shallower decline, a little bit lower IP and a shallower decline and I think we’ve shown that data in the past with the differences in economics what they look like.
So those -- I would say those economics are probably a slight step down, but not something that’s significant if my recollection is correct and that would play into then again back to how many existing vertical well bores are there? How much room on the surface do we have to develop and whole bunch of different factors is to how many Niobrara’s versus Codells and obviously you can see from our counts as we’ve gone through the year and gone through time, we’ve much more focused on the Niobrara with fewer Codells.
And that’s really a function of I think our teams are getting better at making judgments as to when they can have good economic Codells and that would compete with the Niobrara versus some of those Codells that may be didn’t perform quite as well as the Niobraras would.
Okay. And then just to refer back to a prior presentation where you talked about 2016 spuds being a third, a third, a third, I couldn’t have but notice the disconnect between the turn in lines and spuds with respect to XRL.
So you will have only a 10% turn in line and I apologize you’ve got a Analyst Day ahead and I am asking about '17, but is it reasonable to expect that these XRLs would then be turned on line early on in '17 and can I give you a production uplift.
You're exactly on it, what we're doing is starting those two mile drilling projects later this year and many of those get carried into next year as a part of the process of drilling those.
So, you're absolutely correct and the assumption that they move to next year and there will be a significant number of those, the remaining as you said about 10% there that are getting done, the remainder of those will get down early next year and they will be first up in the queue obviously as we do a few of them this year, but they're really still early next year.
Ipsit this is Bart absolutely the extended reach laterals and the two milers being waited more towards the end of the year and into '17 are providing a better foundation of production because the decline on those wells is lower.
So it's part of our planning process as we're going and looking at '17 and it is a benefit for us trying to achieve some type of production growth next year probably at any activity level. We’re still striving for growth profile next year. But we won’t do that without first honoring the balance sheet, but that production really is a nice foundation for us to be building on.
Thank you. Our next question comes from the line of Neal Dingmann with SunTrust. Your line is open.
Good morning guys. Thanks for squeezing me. Let's say Gysle just kind of follow up on the inventory question, I was looking in the K where you guys mentioned about the 791 gross puds in the 1400 gross probable which is reconciled in that versus the 2640 I think on the prior sides suggesting for the 2P locations?
Yes Neal this is Lance. There is two primary factors there. One is the number of wells that we spud in 2015 that would reduce the 2640 down to the combination that you see there. The second thing is that our average lateral length now for our 2P inventory is approximately 4700 feet long. We’re in the past the 2640 was primarily 4200, we’re now targeting around 4700 for average length.
Okay. Okay, certainly makes sense there and then how many as far as just looking that I know I think you put in slide it was 50%, 60% the Utica HPP if you talk about just based on this year growing plan how you guys assume where you'll hold most of that Wattenberg acreage I assume?
Neal we are only holding a small portion of acreage with each of these wells that we drill in the Utica. It really comes down to as we drill these wells we will be using then to make a decision on the remainder and there is some of the acreage that we have as a fairly obviously.
The stuff that’s quite ways west is very oily and it probably has some potential weigh into distant future, but not in the short term in our shorter term look at life here. So we're continuing to gather that production data not only from these new wells but from those wells that we’ve already drilled.
Trying to understand that variability and the productivity and with that then we'll make a decision on the acreage that's expiring. Now particularly we're trying to get information for 2017. That's really why we're drilling these wells this year is to understand how that's going to impact our acreage expansions and what can we afford to pay in and what areas can we afford to pay at.
Thank you. Our next question comes from the line of Irene Haas with Wunderlich. Your line is open.
Yes I have two questions, at $6.5 million right now per well in 6000 foot, how the economics looking in Utica and similarly when you extend it to 10,000 foot would that improve and maybe little color on sort of the liquids market in Ohio area?
And then really for 2017 what are the possible outcome? Would you be shrinking your footprints to the north and south maybe some scenario analysis and if I may one last question how is the CFO search going?
Yes let me start with the last part, the CFO search is ongoing and I think everyone knows Gysle announced his retirement and is here through summertime. So why don't you jump back to…
In terms of the overall economics Irene we looked at the economics today and where we are at and really we need something higher than what we’re seeing today, something more in that $50 range and $3 gas to make these projects economic.
But we see that in the future and that's something that we definitely have that eye as Lance pointed to in A&D market. We have that eye towards the future although we’re in good shape for today based on Wattenberg alone.
So really the economics are straying today and we will continue to work at that. We still see downward pressure on cost there and I think it’s probably fairly substantially yet and I don’t have real numbers but 6.5 is probably not where we would land if we went into a larger longer term program.
In terms of the positive outcomes that is a great question as part of what we’re trying to figure out ourselves I guess is maybe the best answer I can give you but we do see the idea that the Northern acreage is pretty well derisked. We understand it pretty well, I would say and so the acreage up there to us is obviously more valuable, that 10,000 foot lateral may bring more light to and obviously better economics possibly over the 6,000 footers.
So that's why we're working up there. We do see opportunity to expand our position there as we would like to, I think some of our peer companies out there would part ways with that -- with their acreage there but that would obviously come at a price.
The southern acreage when we talk about it, which is where the bulk of our acreage is, there is a little more knowledge to be gained there. So the test down there is obviously pointed trying to be as close as we can to write on what we would call our A plus line in terms of development and understanding those economics there with the Garvin well to the East and the Palmer to the West, we’ve got them good boundaries around what we see and I think we could then identify how far one way or the other do we want to be from the Palmer and the Garvin.
Irene from a liquids market standpoint in that region for 2015, our actual deduct on our condensate itself was just a little over $7 of barrel all in from NYMEX back to the well head. So it’s still a very favorable area for the condensate production and sales there.
From natural gas liquid standpoint it's under lot of pressure. It’s a market that we still see continuous over supply of propane and also ethane. So as we think about that percent for 2016 we're probably all in the neighborhood of that 18% plus or minus as a percent of NYMEX for the company for the full corporation.
We did turn in Utica by itself about 25% in 2015, but we continue to see some of that oversupply on the NGL side.
Thank you. Our next question comes from the line of Paul Grigel with Macquarie. Your line is open.
Hi, good morning. In the 10-K you make reference to the potential reduction in activity in second quarter if prices fall short of -- excuse me, fall short of internal expectation.
With that where are those price expectations? Is that the $50 from the December guidance or is that current strip or something else and then philosophically through 2017 and into 2018, what’s the longer term desire to limit cash flow versus being more focused on growth?
Yeah, based on where we are at right now as we go into '17 our desire is to do everything we can to limit within cash flow Paul. As far as supply, we would love to think we were back at our $50 December outlook. We're long ways from there and I think as I outlined earlier in the call it's not just the pricing outlook.
Obviously if we have a two handle on it, we’re going to give some serious consideration to our capital spend levels, but we need to understand the pricing market here in the next couple of months, if there is any type of modest rebound that's going to occur, that rebound needs to have some legs on it and be something we think is going to lost into '17.
But then all of the other factors that we've been talking about as far as cost structure per well, well performance monoboard drilling any additional discounts pass through from the service providers.
We’ve got a lot of things we're looking at and our deducts in the basin. So all those will go into the final decision and we will be making that over the next couple of months.
Okay. And then just following up on the differential as mentioned in there, they will obviously come in pretty materially not just in the last quarter here, but even in the last few quarters, how much more can those really improve and what’s the key driver of those and continue to come in?
Well and that’s a good question this is Lance, so the key drivers, there is a couple of them. One is the increased capacity take away in pipelines out of the basin. That’s the key driver for the improved differentials.
Also the pace of drilling coming down within the basin from the E&P side is also enabling more space going to become available on the various pipes coming out of basin. So yeah, since December we're down about a dollar on the differential in the Wattenberg Field.
Our marketing teams have done a wonderful job to continue to find incremental contracts that are more and more favorable going forward. We believe in general there will be some continued improvement on that, but at this juncture, we don’t want to quantify any specific numbers to that as we want to be able to see how the market plays out over the next several quarters.
Thank you. Our next question comes from the line of Jason Smith with Bank of America. Your line is open.
So, oil production in the quarter was about 44% and I think your guidance for 2016 is 42%. Your comments earlier implied trailing fewer inner core wells and obviously those are a bit gassier. So just want to check first of all the 42% still holds and we should think about that trajectory into 2017?
Jason I guess the way we look at that is we're really turning in line a bunch of those inner core wells as we speak. That's part of what drove late 2015 and will definitely drive early 2016 gas production higher and thus drop that oil percentage slightly.
As we go through this year though, we'll start to go the other direction again and it's really a function of using a bunch of that inner core inventory in order -- in the process we'll be seeing those percentages go down, come back up in terms of oil and then what we land on particularly is mostly just inner core wells.
So it should stabilize back toward that middle 40% of oil over time and every now and then we'll toss in there an inner core type well or an outer core type well, but generally the middle core type curve is what's going to drive it.
Thanks Scott and just a follow-up on the Utica, I think you made a comment earlier about the lease extension decisions in 2017, can you just quantify how much of your acreage that potentially impacts?
And I don’t know if I have a number for you. We've always talked in terms of dollars and it's in that $30 million range, but I don’t have a good number of acres, I would have to get that number.
Thank you. Our next question comes from the line of Mike Scialla with Stifel. Your line is open.
Yes hi guys. Any update on the regulatory front in Wattenberg and I want to see how if at all that plays in your decision on lateral length and the economics you see on Page 17 does that include any benefit from fewer surface facilities with longer laterals?
Oh boy, I'll let Scott jump on the last one as far as '17 but let me touch on Colorado, Wattenberg and lateral length, let me start here, absolutely the extended reach laterals in the two milers are a huge benefit to the current environment in Colorado and that is because capturing resource with less surface impact is a critical step that operators are taking to try to work with land owners in the State of Colorado.
So we besides the returns in the extra capital efficiency and the value add, we would love to migrate to more ERLs in two milers and I think our peer operators feel the exact same way and it’s the best win-win for communities, land owners and the energy companies.
As far as Colorado and Wattenberg we just finished with the rule making on the commission that was formed year and half, couple of years ago. There were 19 resolutions from that, two or three of them had significant debate in the rule, like I said the rule making was just completed.
And it’s a series of additional urban development planning regulations that the operators are dealing with now. And I think it was a compromise between the opposition and industry. It’s something that PDC can manage its way through.
We feel about 10% of our acreage is exposed to these additional rigs. It won’t slow down our pace. It won’t change our pace and it won’t eliminate that 10%. It just adds additional really for Scott and the operating teams, additional management around noise, dust control, pad locations some things. So overall that's where we're at why don’t you talk about?
Structure yes and Mike I think we do all we can to build all the efficiencies into our cost. So the $26 million, $36 million, $46 cost millions of dollars per well is fairly reflective of the cost that we’re spending at the time with one caveat.
Obviously we've not drilled two milers yet. And so that's as good estimate as we could come up with for the XRLs based on what we see from the drilling records from other companies and that kind of thing.
But we really do try to build all those efficiencies in including Lance’s team putting together with the field operations teams now the idea that we’re piping oil out of the area there and the reduction in tanks, the increased cost of lack unit that type of thing.
Okay. Great and then just want to explore little further on your rig contracts Bart you had mentioned they are short term, could you give any more specifics there? How many roll off this year and are any of those on a we'll-to-well basis?
Yes Mike this is Scott again. We have two contracts that are on 30 days and two that are on 90 days. In the Utica one is on a well to well basis pretty much so. I think that pretty well describes the circumstances we're in, very flexible.
Our next question comes from the line of Michael Glick with JPMorgan. Your line is open.
Good morning, Michael.
As you'll move towards longer laterals in Wattenberg, how are you thinking about the relationship between your lateral length?
Well I think, so Michael this is Lance, how we look at that is from where we sit today, first off the mile and a halfers that we have, are about 600,000 barrels that represents about 6900 foot overall.
That compares to our standard length lateral, which is 4200 feet, that's about 440,000 barrels per well and both of these are middle core, both of these are Niobrara. So you kind of see the relationship from that.
As we look at the two milers, clearly when we look at A, relationships like that, to sort of our first estimates based upon that lateral foot relationship that's shared with there, but also we want to look more at industry and see how the industry results are coming in also.
So those are really the two key factors that we rely on to say what ultimately will be the two mile EURs and that's still very much in progress with our reservoir teams.
Just to add one thing I think and I would say we don't see a full multiple. So if you see a 50% longer lateral, we don't quite expect 50% more production. So a doubling we wouldn't expect quite doubling in the lateral length, we wouldn't expect quite a doubling in the productivity.
Got it. And just a question of access frac, understanding the statistical range you went through earlier relative to your plug-and-perf, is there any technical reason why performance of access frac with plug-and-perf would differ from access frac on a standalone basis?
We could have a really long conversation. The answer is yes, there is a lot of reasons why it should work and a lot of reasons why it might now and you get into the particularly distributing perks more evenly across a length of that what would normally be a sliding sleeve packer distance.
And that distribution maybe taking place more effectively because of the perforated plug-and-perf process than it does with the sliding sleeve. So that's one example where it may not work, but there is also the idea when we look at our perf count and calculate what we believe the number of perfs that are open happens to be at any particular time, we don't see them all open. So it points in both directions I guess is the best answer.
Our next question comes from the line of David Beard with Coker & Palmer. Your line is open.
Good morning, guys. Congratulations on a nice quarter. Most of my questions have been asked. So I'll pass the time.
Thank you, David.
Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open.
Good morning. The first question I wanted to ask was that I've actually heard two different things on the call today and I want to better understand it. on the one hand you said the two milers are difficult to put together with industry peers, yet they're important to regulators and land owners.
So how do we reconcile with two? Do you think regulation can push producers to block more acreage over time?
Let me clarify. I think what Scott was saying is its more challenging, it's not impossible. So when we look at the two milers, we recognize that there is other operators we're going to have to work with and it becomes just more cumbersome for land groups to get that done.
I don't think we're seeing the efforts will not -- will be unsuccessful. So Jeffrey I think it takes a little more effort, it takes more planning and I do believe that the comp perspective of energy development in the State of Colorado particularly Weld County or the Wattenberg Field absolutely will be a positive force and operators working together to try to do more extended reach or two miler type projects.
You always have the challenge of different operators looking across the table and saying there is operator ship, there is JOA, there is all those pieces in part. You have to negotiate. That can be challenging for not only PDC, but our peers, but we generally have good relationships with all of our peer operators here.
So I think the market can expect that to become more of a norm as we define the projects and again it's very important on these two milers we want to get a handful of these under our belt.
Technically no, we're not increasing our operational risk and then really understand the reserve performance of the wells and if all that comes together, expect that to be more of our business plan going forward.
Okay. Thank you. That was helpful and the other question I will ask is that Lance mentioned that line pressure seemed to be getting a little bit more favorable as there has been some general decline because of the terrible commodity prices.
First thing I was just wondering if you mentioned it before and I missed it, I apologize, have you -- can you say what's the production uplift that you're expecting from the AKA compression expansion March and to follow that, do you see any further compression projects likely in the near term or is there decline activity going on for now?
Yes, so the AKA compression expansion is really more normal course. We were very closely with the MR teams and their teams together to discuss with them the growth in our gas volumes into their systems because we have acreage that's dedicated to them as well.
And so what they have is an expansion of their compression so that they can accommodate the growth that we have in 2016 and all that's been factored into our guidance for production for 2016.
Thank you. And I am showing no further questions at this time. I would like to turn the call back to Mr. Bart Brookman for closing remarks.
Yes. Thank you operator and thank you everyone for the questions and the ongoing support and I encourage everybody to plan around April 7, that is our Analyst Day, which will be held in Denver this year for the company. You can attend or you can call in. So again, thank you for the time.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a wonderful day.
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