PDC Energy Inc (PDCE) 2015 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy 2015 fourth-quarter conference call.

(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 posted a slide presentation that accompanies our remarks today on the Investor Relations page of our website, 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. But 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 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 are extremely pleased with our 2015 results. We enter 2016 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 2016 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 2015 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 year-end 2014 levels, and a 247% reserve replacement level for the Company. Our lifting costs decreased approximately 20% year over year to $3.71 a barrel, a tremendous accomplishment on the part of our operating teams, particularly in an environment of ever-increasing regulatory costs. And last, we greatly improved our EH&S statistics, a combined effort of our EH&S and operating teams.

From a financial perspective, our year-end 2015 debt to EBITDAX, we exited the year at approximately 1.4. The liquidity of the Company at year-end 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 am 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 produce 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 are we 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 the continued decrease in our per-well costs 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 moment. We feel fortunate to have this operational flexibility, given our acreage is held by production and our rig 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.

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 a more detailed description of the performance for the quarter and the 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 a 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.

That's the high-level summary; now, let's get into some of the metrics for the fourth quarter on slide 7. Starting with oil & gas sales, again this quarter, year-over-year production increased over 85%, while our fourth-quarter total sales of oil & gas was only up 3% compared to the fourth-quarter 2014.

Oil and all commodity prices declined year over year and quarter over quarter. Crude oil for the fourth-quarter 2015 averaged $35.26, down 42% from the fourth-quarter 2014. Average natural gas prices were down 48% from the fourth-quarter 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 2014, 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 costs on a per unit measure were down 19% year over year. Production costs include lease operating expense, production taxes, transportation, gathering and processing. I do want to mention that in our press release we went into detail on how we've reclassified production costs in G&A. While total expenses have not changed, the reclassification is intended to better-align our costs with how peers report LOE and production costs.

For the fourth-quarter 2015, we've averaged $4.81 per barrel of oil equivalent, down from $5.92 per BOE compared to the same quarter last year. For the full year, 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 a big decrease in commodity prices, nearly offset by a strong decrease per BOE and total production costs. For the full year, the gross margin was 77%, down from 85% for the FY14.

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'll 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 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 2014, while for the full-year 2015, it was up to $11.32 from $9.93 for the year 2014.

DD&A includes depreciation of fixed assets and depletion of oil & 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 2014. 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, from $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 a one-time litigation charge of $40.3 million in 2014.

Moving to slide 9, the 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 drawing $37 million, down from $50 million at year end in Q3 2015. Our debt to EBITDAX at year end was approximately 1.4 times, as Bart mentioned. With a borrowing base of $700 million, net of $12 million letter of credit, we had approximately $652 million of liquidity at year end.

Our $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 a B-plus rating by S&P recently. We've not heard from Moody's yet, who is also undergoing a review of high yield in the E&P sector.

The last slide shows our hedge positions. Our hedges for 2016, 2017 and 2018 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. On the 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 were 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 have simplified the way our production costs 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 costs 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 year-end reserves came in at 273 million barrels of oil equivalent, a 9% increase over year-end 2014. Our proved developed reserves as of year-end 2015 were 71 million barrels of oil equivalent, down slightly from 75 million barrels of oil equivalent at year-end 2014.

Our year-end 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 refrac 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 middle 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 1/3 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 have 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 have realized thus far. As it stands, our standard-, mid- and extended-reach lateral wells, including plug-n-perf, are coming in at $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 costs 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 PV10s for both standard- and mid-reach laterals, after considering the improvements in both well costs and basin oil differentials. We elected to exclude our extended-reach laterals from this slide for now, as we have 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 out-year 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 at recent strip pricing, both standard- and mid-reach lateral wells deliver solid rates of return that more than double our weighted average cost of capital.

Standard-reach lateral wells have a slightly higher internal rate of return than mid-reach laterals, due to lower costs 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 unhedged 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 XRL 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 a second-half event, with results most likely in the 2017 timeframe.

We have gained enough confidence in mono-bore drilling to shift our standard- and mid-reach lateral wells to this method, and we will target to do the same with our XRL wells after successfully completing a few in the traditional method. So far, mono-bore drilling is saving up to one day in our drill times, and we're confident we can improve on this number.

As we mentioned in our December press release, aside from a few carryover sliding sleeve wells, we've shifted our entire Wattenberg program to include plug-n-perf completions, and are now testing the additive effect that access 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, DCP's Grand Parkway did a great job piggybacking on their Lucerne II project from last year, and we continue to see favorable line pressures throughout the Basin. Also of note: earlier this year, we began piping oil directly from the wellhead on the Saddle Butte system. We're excited in this development, as it leads directly to reduced truck traffic and well-site emissions, and other environmental benefits. As we have in the past, our in-depth technical update at Analyst Day in April will 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 downspacing and mid-reach lateral project, the Chestnut pad, continues to track our 600,000-BOE type curve, as our plug-n-perf wells on the standard-reach laterals continue to outperform the sliding sleeve wells. As a reminder, up to 15% production improvements related to plug-n-perf technology was included in our 2016 production guidance. And the costs associated with plug-n-perf is included in our current well costs. We are still in the data-gathering phase on our 22- and 26-well equivalent downspacing tests, as well as plug-n-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 Cole 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 Cole and Dynamite. Finally, the Neff well is located in between the Cole and Dynamite pads, and will test the efficiencies of increased lateral length, as it will have a 10,000-foot lateral.

We're currently projecting well costs 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 to the moderator for Q&A.

(Operator Instructions)

Our first question comes from the line of Mike Kelly with Seaport Global Securities.

Thanks, good morning, guys. First question, I guess, would be for Scott, kind of following onto his 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 mono-bores work and also you're getting incremental uptick from access fracs, where do you think you could take those returns on page 17, with kind of both those scenarios working, everything else held constant? Thanks.

And I guess the best answer to that is that we're still looking at that. Obviously the mono-bore is a timesaving process. And I still think that the costs per day, when you're all-in, including the cost of the drilling rig and all the ancillary 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 it's going to be a little harder to see when you start doing that with plug-n-perf wells, because the range on the plug-n-perf wells is still fairly broad. When we talk that 15% to 25% range, you can see, 5% to 10% mixed in with that from the access frac makes it more difficult to see the real benefits.

So we'll probably have to do more testing on the access frac, combined with plug-n-perf, than 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 costs come down and the production improvements 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 to hear your expectations for the spring borrowing base re-determination 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 a hedge book in 2016, which is great, kind of rolling off 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'll 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 that we'll 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 stretched, at that level. And we can maintain cash flow-neutral in 2016, and not grow that borrowings throughout the year.

So 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 still may be some opportunities to get decent hedges for 2017. As I mentioned, we have doubled our position in oil hedges in 2017 in the last two months, just picking up opportunities, at an average price of roughly $48. I hope we lose money on those hedges. We will 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 have modeled internally ad nauseam, low prices through 2017. And we show that we can continue operating at 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.

Hi, good morning.

Hi, David.

I don't know if maybe you said this and I missed it. But as far as well costs go, just that decrease at your end, is that all service-cost reductions? Or kind of 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, that we've seen a little bit of continued improvement there -- maybe 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 providing lower prices. And it's very competitive out there, as you can imagine, with that 400-rig count kind of looking at us square in the face. There's a lot of excess capacity.

And so really, we're still seeing that downward pressure, and it sometimes surprises me. I'm 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 of the different services on a fairly consistent basis, and staying in close touch with the service companies to get those costs to continue to come down. And we still see downward pressure, David.

All right, thank you 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 clearer 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 then 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.

Thank you. Good morning, guys.

Good morning.

So Bart, in your opening remarks, you talked about a focus on commodity prices, cost [control] and cash-flow neutrality. But more specifically, are there any leverage liquidity or any other metric that we focus as you decide on whether or not you want to issue equity at these levels? And similarly, are there any metrics that we can focus on besides cash-flow neutrality as you are try and decide on the right levels of activity for 2016 and 2017?

Let me jump in here on this. First and foremost, as Scott talked about, right now we're looking at different pricing scenarios, whether it's strip -- we 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 are, coupled with our hedges in 2016, managing around the balance sheet. And whether that's cash-flow neutrality, slightly positive in some scenarios, maybe just a little bit of an overspend, but we're really targeting that cash-flow neutrality.

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 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 that it's probably towards the end of this year or sometime in 2017. But I think we also recognize that there's risks that could push deep into 2017, or potentially 2018. 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 downspacing and access frac results, and the production enhancement from those. 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 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's additional improvement coming through, we're trying to really define all of 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 a 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 of that, I think you can expect over the next couple of months -- we are 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, your 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 in our capital spend. And that, we believe, we can do as we go through 2016.

Got it. That's a really helpful answer, Bart. And on somewhat of an unrelated note, last quarter, you talked about a 60-well inventory through 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 there is more in 2017 points.

Yes, 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 it 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 toward the end of 2016, and manage our growth in 2017, 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 our operating teams. They are really set up with the four rigs to obviously drill a pad out, build a schedule, work 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 say. And that ends 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.

Hi, guys. Bart, maybe this is right to one of your last points. On the downspacing, where do you all -- how much more do you need to see? And can you maybe talk about, is there an average how many wells per section, or the equivalent of, that you're drilling in 2016?

This is Scott, Brian. I'll start, and Bart may jump in here. But I look at this, and our plans for this year are primarily focused around the 20-well per section equivalent spacing. And that's a combination of Niobrara and Codell wells, and it's a lot of function of the number of wells already in the section, and a number of factors that play into that.

In terms of the looking at the tests that we're running currently, as you well-know, we tend to lean toward the 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 we'll have -- it will help us determine what the next steps are, and how we approach late 2016 and early 2017. So we see good data. We will hopefully have that data at Analyst Day. I'm not 100% sure, because I haven't looked at it in awhile, what it will tell us. But I think we're there in terms of understanding at least that 22- and 26-well count.

And again, I have to caution everybody about just saying: well, will you go drill 26 wells if it works? The answer 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-n-perf. It sounds like you're adding, I guess, about 15% to production as a result. It seems conservative. Is the average -- what has been the average improvement? Has it been 25, or is it not quite that high?

Yes, 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 and in a particular area. And it's only on our standard-reach laterals. So the mid-reach and long-reach laterals don't have any of that in them, because generally, they were drilled with plug-n-perf technology in the first place.

So it's really the standard-reach laterals, and has everything to do with being early-data and 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 by better utilizing the plug-n-perf method.

Our next question comes from the line of Brad Carpenter with Cantor Fitzgerald.

Good morning, guys. Thanks for the update. Bart, I was hoping to get your thoughts on M&A. You've previously mentioned your team is working on an internal basis study that would help frame some of your decisions. But I was curious, given the additional down-tick 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 sort of 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 years to come. We continue to do our basin study work, and look for other basins in 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 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 and tremendous people that really know and understand this basin and have worked in the DJ for a long period of time. So we feel very comfortable where we are today. We'll continue to monitor the A&D market. That's part of our businessman plan, that's part of our long range plan that we look at. But our focus is really on the organic side of what we have.

Okay, great. And then

Brad, the only thing I would add on that, like Lance said, is, we'll continue to monitor. I think we've 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 the pain 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 staying with the theme of the solid returns in the Wattenberg, Bart -- or maybe this one is for Scott, whoever wants to take it. Your team has done an impressive job of proven 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 inner cores that you draw on your map, at least from a well level of return standpoint?

It's very hard to answer that question. I'd 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-n-perf operations, we've tested it in a limited 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 aren't 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 will be limited and they will be infrequent.

And so we're really looking at the middle core as our primary focus. And I think, is it such that we're blurring the lines 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-n-perf-type technology.

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

Thank you, and good morning, folks. Can you speak to how the Company's acreage is set up for XRL wells? That is, how much acreage can be drilled with the XRLs, and/or how much inventory can be converted under that assumption on lateral length? I ask that question in the context of the weighting to SRL wells and drilling activity this year and last year, and whether that weighting will change and maybe change meaningfully in the periods ahead?

I think when you look at our acreage, it's -- 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's an opportunity to drill all of the wells at that two-mile length, but we'd just end up including other peoples' interest in our wells. And 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 aren't all that great when you look at the rates of return and the PV10s. It is such that we're more efficient obviously, but not to the point where it's worth really pushing with 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 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, that shows very specifically how those wells change over time. In about 18 months, 24 months, we really see that GOR stabilize. And so Mike Edwards is laying that in front of me. But it gives the best indication of what we expect over time in both the inner and middle core, as well as outer core.

Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors.

Thank you, good morning.

Good morning Michael.

I kind of wanted to follow on a little bit on one of the questions from earlier around your sensitivity to current pricing relative to your activities profile. I was curious, on slide 17, are those returns at the field level, or are those kind of full-cycle, fully burdened land and hook-up, et cetera?

Those are front-line level, including all deducts and all, call it, direct costs to the AFE.

Yes, including the equipment, the drilling and completion, and as Bart said, a net back to the wellhead prices.

And so at what price, like in the current environment, where you're eking out a 20% returnish -- on a full-corporate basis, I imagine that's still clearing the full cost, but getting close there. At what point do you -- what price do you budge, I guess, and reduce the activity profile?

Again, it's not specifically just the price, Michael. It's a combination of price plus anything Scott and his teams can squeeze out of this cost structure. It's mono-bore drilling, and the times, and how that improves capital efficiency. It's some of these continual production enhancements that we have.

So we've really got to throw all of that together, along with, Lance and our marketing team continue to make strides in our deducts. So we've got all of these factors, and it's why we don't want to over-react. And as I said earlier, we still believe there's a rebound.

I can tell you this though. If oil stays with a 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 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 on our rigs, and we can move pretty quick. And I should note, we can move either way pretty quick. We can slow her down or 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 Fitzpatrick with Johnson Rice.

Hi, guys, good morning.

Hi, Welles.

Scott, you hit on this a bit, but any specific update on the Rieder pad? And if your location count does jump up to that 26, how does that change the way that you think about the hurdle rate for M&A, given that your number of locations is obviously going to be much higher?

I'll speak to the Rieder, and then hopefully Lance can give you 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 Rieder 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 well-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've got there.

And again, I'm hopeful that we'll 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 in one of those conversations that goes on quite some time there at a 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.

Welles, this is what I'd add to that. When you look at our inventory, as 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 would have a positive impact on the inventory count.

So as we think about that, I think it gets back to the fact that we are very fortunate to have such a tremendous field in the Wattenberg core area, because it's a tremendous organic growth profile for many years to come. So we have a top-tier asset, one of the -- what we believe to be the very best in the US 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, 2,000. Is that just 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 fringe-ier 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 that 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 of the 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. And I think we talked on the order of about $30 million worth of renewals, if we extend it -- and that's a big if -- if we extend it, all that acreage that's expiring.

Our next question comes from the line of Ryan Oatman with Cowen and Company.

Hi, good morning, and thanks for taking my questions. You kind of inferred that -- where I was going 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 front-end loaded. And that's on the maintenance program that we mentioned in December, with four wells running for the full year. Now if we change that, because of the economic conditions of pricing, then it would likely affect the last half of the year and not the first half of the year. Scott, do you have anything to add?

Yes, I can add a little bit to that, I guess. When you look at the 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 front-end 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 front-end loading that. With 2/3 of the total well costs being completions, you can see how that would drive that early-time capital in the first part of this year.

Got you, that makes sense, with the implication being that, that second crew will drop sometime later this year.

Yes, at this point it's scheduled for sometime second quarter, is really what our teams have it scheduled at, 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 sort of run rate G&A we should be looking at 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 until 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.

Hi, good morning, guys. Just looking at slide 17, wonder how those numbers will change your trend if Niobrara is replaced by Codell? So in other words, your decision to go on a Cordell development, would it change at all based on these returns? Or would it be more of the drainage and all of those other geological issues?

I think when you look at it, obviously when we move into an area, if we're drilling, we want to drill all of 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 when we make that decision, obviously those economics become critical. And the Codell wells do come on with a little shallower decline, a bit lower IP, and shallower decline. And I think we've shown that data in the past with the differences in economics, what they look like.

So 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 a whole bunch of different factors as to how many Niobraras 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 have good economic Codells that would compete with the Niobrara, versus some of the Codells that maybe didn't perform quite as well as the Niobrara's would.

Okay. And then just to fall back to the presentation where you talked about 2016 spuds being a third, a third, a third, I couldn't help but notice the disconnect between the turn in lines and spuds, with respect to XRL. So you'll have only a 10% turn in line. And I apologize -- you were at Analyst Day, I heard, and I'm asking about 2017. But is it reasonable to expect that these XRLs would then be turned online early on in 2017, and kind of give you a sort of production uplift?

That's exactly -- 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 in 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 done early next year. And they will be first up in the queue obviously, as we do a few of them this year. But they will really see it early next year.

And Ipsit, this is Bart. Absolutely the extended-reach laterals and the two-milers being weighted more towards the end of the year and into 2017 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 2017, 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 a 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.

Good morning, guys. Thanks for squeezing me in. Say, guys, just to follow up on the inventory question, I was looking in the K where you guys mentioned about the 791 gross spuds and the 1,400 gross probable, which is reconciling that versus the 2,640, I think, on the prior slides, on the suggestion for the 2P locations.

Yes, Neal, this is Lance. There's two primary factors there. One is the number of wells that we spud in 2015 that would reduce the 2,640 down to the combination that you see there. The second thing is that our average lateral length now for our 2P inventory is approximately 4,700 feet long. Where in the past, the 2,640 was primarily 4,200, we're now targeting around 4,700 as an average length.

Okay, certainly makes sense there. And then how many, as far as just -- we're looking at, I know, I think, you put in the slides, it was 50%, 60% of the Utica HVP, you talked about just based on this years drilling plan, how you guys assume what you'll hold most of that Wattenberg acreage, I assume?

Utica?

Yes, 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 them to make a decision on the remainder. And there's some of the acreage that we have, has a fairly obvious decision. The stuff that's quite a ways west is very oily, and it probably has some potential way in the 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 we've already drilled, trying to understand that variability in the productivity. And with that then, we'll make a decision on the acreage that's expiring. But 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 extensions, and what can we afford to pay, and in what areas can we afford to pay it.

Thank you our next question comes from the line of Irene Haas with Wunderlich.

I have two questions. At $6.5 million right now per well, and 6,000 foot, how are the economics looking in Utica? And similarly, when you extend it to 10,000-foot, would that improve? And maybe a little color on sort of the liquids market in Ohio area? And then really for 2017, what are the possible outcomes -- would you be shrinking your footprint, stick to the north and south to south? Just some scenario analysis? And then if I may, one last question is, how is the CFO search going?

Let me start with the last part. The CFO search is ongoing. I think everyone knows Gysle announced his retirement, and is here through summertime. So why don't you jump back to --?

Okay. In terms of the overall economics, Irene, we looked at the economics today and where we're 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 is something that, we definitely have that eye, as Lance pointed to, in the A&D market. We have that eye toward the future, although we're in good shape for today, based on Wattenberg alone.

So really, the economics are strained today, and we'll continue to work at that. We still see downward pressure on costs there, and I think that it's probably fairly substantial 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 possible outcomes, that's a great question. It's 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 de-risked. 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, if we would like to. I think some of the peer companies out there would part ways with that 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's a little more knowledge to be gained there. So the test down there is obviously pointed at trying to be as close as we can to right on what we 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 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.

You know, Irene, from a liquids market standpoint, in that region for 2015, our actual deduct on our condensate itself was just a little over $7 a barrel all-in, from NYMEX back to the wellhead. So it's still a very favorable area for the condensate production and sales there. From natural gas liquids standpoint, it's under a lot of pressure. It's a market that we still see a continuous oversupply of propane, and also ethane.

So as we think about that percent for 2016, we're probably all-in, in the neighborhood of sort of 18%, plus or minus, as a percent of NYMEX for the Company, for the full Corporation. We did turn in, 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.

Hi, good morning. In the 10-K, you make reference to the potential reduction activity in second quarter, if prices fall short of internal expectations. With that, what are those price expectations? Is that the $50 from the December guidance, or is that current strip or something else? And then philosophically, as you enter 2017 and into 2018, what's the longer-term desire to limit cash flow versus being more focused on growth?

Based on where we're at right now as we go into 2017, our desire is to do everything we can to live within cash flow, Paul. As far as -- we would love think we were back at our $50 December outlook. We're a 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 months. If there's 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 last into 2017.

But then all of the other factors that we've been talking about, as far as cost structure per well, well performance, mono-bore drilling, any additional discounts passed through from the service providers, we've got a lot of things we're looking at -- and our deducts in the basin. So all of those will go into the final decision, and we'll be making that over the next couple months.

Okay. And then just following up on the differentials mentioned in there, they've obviously come in pretty materially, not just in the last quarter here, but even over the last few quarters. How much more can those really improve, and what's the key driver of those and continuing to come in?

Well, and that's a good question. This is Lance. So the key drivers, there's a couple of them. One is the increased capacity takeaway and pipelines out of the Basin. That's a 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 is going to become available on the various pipes coming out of the Basin.

So yes, 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.

Hi, everybody.

Hi, Jason.

So oil production in the quarter was about 44%, and I think your guidance for 2016 is 42%. Your comments earlier implied drilling fewer inner core wells, and obviously, those are a bit gassier. So I just wanted to check, first of all, if the 42% still holds, and how we should think about that trajectory into 2017?

Yes, 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 the process, we will 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%s 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?

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'd have to get that number.

Our next question comes from the line of Mike Scialla with Stifel.

Yes, hi, guys. Any update on the regulatory front in Wattenberg? And wanted to see how, if at all, that plays into your decision on lateral length? And curious, too -- the economics you show on page 17, does that include any benefit for fewer surface facilities with longer laterals?

Oh, boy. I'll let Scott jump on the last one, as far as 2017. But let me touch on Colorado, Wattenberg and lateral length. Let me start here. Absolutely, the extended-reach laterals and the two milers are a huge benefit to the current environment in Colorado. And that is because capturing reserves with less surface impacts is a critical step that operators were taking to try to work with land owners in the State of Colorado.

So we -- besides the returns and the extra capital efficiency and the value-add, we would love to migrate to more ERLs and 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 a year-and-a-half, couple years ago. There were 19 resolutions from that. Two or three of them had significant debate in the rule-making. 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 that 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 regs. 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, per Scott's and the operating team's additional management around noise, dust control, pad locations, some things. So overall, that's where we're at. And why don't you talk about --?

Cost structure? Yes, and Mike, I think we do all we can to build all the efficiencies into our costs. So the $2.6 million, $3.6 million, $4.6 million cost per well, is fairly reflective of the costs that we're spending at the time, with one caveat: obviously, we've not drilled two-milers yet. So that's as good an estimate as we can come up with for the XRL, based on what we see from the drilling records, from other companies, 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 to the [lack] unit, that type of thing.

Okay, great. And then just wanted to explore a little further on your rig contracts. Bart, you'd 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 well-to-well basis?

Mike, this is Scott again. We have two contracts that are on 30 days, and two that are on 90 days. And 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.

Good morning.

Good morning, Michael.

As you all move towards longer laterals in the Wattenberg, how are you thinking about the relationship between EUR and 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, and that represents about 6,900-foot overall. That compares to our standard-length lateral, which is 4,200 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.

You know, as we look at the two-milers, clearly, we will look at A, sort of relationships like that, that sort of -- our first estimates based upon that lateral-foot relationship and the EUR that we just 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 sort of 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 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 in the lateral length, we wouldn't expect quite a doubling of the productivity.

Got it. And then just a question on the access frac. Understanding the statistical range you went through earlier relative to plug-n-perf, is there any technical reason why performance of access frac with plug-n-perf would differ from access frac on a standalone basis?

We could have a really long conversation. The answer is yes, there's a lot of reasons why it should work and a lot of reasons why it might not. And you get into the particularly distributing perfs more evenly across a length of what would normally be a sliding sleeve packer distance. And that distribution may be taking place more effectively because of the perforated portion -- the plug-n-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 you both directions, I guess, is the best answer.

Our next question comes from the line of David Beard with Coker & Palmer.

Good morning, guys. Congratulations on the nice quarter. Most of my questions have been asked, so I'll pass the baton.

Thank you.

Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers.

Good morning. The first question I wanted to ask was, I actually heard two different things in 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 are important to appease regulators and land owners. So how do we reconcile the two? Do you think regulation can push producers to block more acreage over time?

Let me clarify. I think what Scott was saying is, it's more challenging. It's not impossible. So when we look at a two-miler, we recognize that there's other operators we're going to have to work with, and it becomes just more cumbersome for our land groups to get that done. I don't think we're saying the efforts will be unsuccessful.

So Jeffrey, I think it takes a little more effort. It takes more planning. And I do believe that the current perspective of energy development in the State of Colorado, particularly Weld County, or the Wattenberg Field, absolutely, it will be a positive force, and operators working together to try to do more extended-reach for two-miler-type projects.

You always have the challenge of different operators looking across the table and saying that -- there's operatorship, there's JOAs, there's all those pieces and parts 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 out here. So I think the market can expect that to become more of a norm, as we define the projections.

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'll ask is that Lance mentioned that the line pressure seemed to be getting a little bit more favorable, as there's 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. Can you say what's the production uplift that you're expecting from the AKA compression expansion in March? And to follow that, do you see any further compression projects likely in the near-term, or is the decline in activity good enough for now?

So the compression expansion, it's really more normal course. We work very closely with them, our 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. So what they have is an expansion of their compression, so 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. I'm showing no further questions at this time. I'd like to turn the call back to Mr. Bart Brookman for had 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. And 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.