PDC Energy Inc (PDCE) 2015 Q2 法說會逐字稿

Welcome to the PDC Energy 2015 second-quarter conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr Michael Edwards, Senior Director Investor Relations. Mr Edwards, you may now begin.

Good Monday 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 have 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 and the reconciliation of non-GAAP financial measures. With that, we'll get started. I'll turn the call over to Bart Brookman, CEO.

Thank you, Mike. Hello, everyone. We're extremely pleased with the second quarter. We had record production levels for the Company. A record number of completions in horizontal turned-in-lines by our operating teams. Our drilling efficiencies continue to improve at a dramatic pace leading us to reguide 2015. Today, we will also update our outlook for 2016.

Let me start with second quarter highlights. Production increased to approximately 37,000 barrels of oil equivalent per day. This is a 15% jump from the first quarter of 2015 and a 46% increase from the same period 2014. 47% of the production mix is oil. Our drilling efficiencies have improved approximately 30% from a year ago, enabling the Company to continue delivering value on our drilling programs. For the quarter, we turned-in-line 44 wells, a large portion of those being extended-reach laterals. The Cole four-well pad in our Utica play in Ohio is performing well above our expectations. Scott will cover this in more detail in a moment. Our operating costs for the Company continue to improve, with lifting costs now under $4 per barrel of oil equivalent for the quarter. From a financial perspective, the cash flow for the quarter was $97 million. The balance sheet for the Company remains incredibly strong with a debt to capital of 34%. We are currently projecting exiting 2015 with a debt to EBITDAX under 1.5.

For the for the balance of the year, expect the following. Continued strong production growth in the third and fourth quarters. We expect to be cash flow neutral for the remainder of the year. Our operating teams will continue with their ongoing focus and testing of technical improvements and expect strong discipline around our balance sheet. Last, let me thank both our Wattenberg and Utica EH&S and operating teams for achieving 800 days without a lost time safety-related incident, a tremendous accomplishment.

Now let me give some highlights for our updated 2015 guidance. I will speak to midpoints on most of the components and Scott and Gysle will give a lot more detail in a moment. Production is now forecasted at 14.85 million barrels equivalent, that is a 60% increase from 2014 levels. Cash flow expectations for the Company have increased to $410 million, with an adjusted price deck for the balance of the year of $48.98 a barrel and $2.87 per Mcf. The capital spend for the Company is slightly higher at $535 million, primarily due to the drilling pace, which we will cover in a lot more detail throughout the call, but also the number of non-consent projects in the Wattenberg Field. Our cost per well continues to improve; $3.1 million per well for our standard-reach laterals and $4.1 million for our extended-reach laterals. Overall, we are increasing our spud counts to approximately 155 wells from a prior guidance level of 119 wells. This dramatic increase in drilling efficiencies has enabled us to continue with our strong growth heading into 2016 while reducing our Wattenberg rig count to four rigs in the fourth quarter of 2015. This will result in approximately 140 wells drilled in 2016, continued production growth over 35% next year, continued growth in the cash flow of the Company, the capital spend approximately equal to cash flow as we target cash flow neutral position for 2016, all while we continue improving the strength of the balance sheet. Lance will cover this 2016 forecast in much greater detail later in the call. Again, we're extremely pleased with the quarter. Our operating performance, particularly on the drilling side and the resilient plan we are putting in place during these challenging industry times.

With that, I'm going to turn the call over to Scott, who will give a lot more detail on our operating results.

Thank you, Bart. Good morning, everyone. I'm going to start by going over some of our second-quarter and operational highlights before shifting gears and discussing our updated guidance in a bit more detail. As Bart mentioned, we are very pleased with the second quarter. Production totaled 37,000 barrels of oil equivalent per day, a 46% increase from the second quarter of 2014 and a 15% increase sequentially. We did a great job meeting our internal targets despite facing some serious headwinds, including a very wet spring season in Colorado, which resulted in a lot of mud, vertical well shut-ins, completion delays and general logistical challenges. Additionally, we were able to work through high line pressures prior to Lucerne 2 coming online and adjusting to the new pace with which we are drilling at this point.

So on slide 8, I'm going to cover the second quarter highlights further. During the quarter, we spud 43 horizontal operated wells and turned-in-line 44 horizontal wells, both Company records. Included in these numbers was our first batch of extended-reach lateral wells located on the inner portion of our middle core. Early results are encouraging. We will discuss this more in a minute. Oil accounted for a record 47% of total production and grew 47% year-over-year and 20% from the first quarter of this year.

You can see on slide 9 that from a development standpoint all five of our rigs are currently located in the middle or inner core. The right-hand side of the slide shows the status of a couple of our key projects for 2015. As you can see, all of our Chesnut and Churchill projects are currently producing. The other extended-reach lateral and downspacing projects have been moved up a bit in the schedule to account for the faster drill times we are experiencing. Results from these tests are most likely in the 2016 timeframe. I'd like to point out that these tests are being conducted throughout our acreage position and not focused in one specific region. In terms of downspacing, you can see the timing of our current projects, but I will point out that our Sunmarke pad, the 20-well equivalent test that was turned-in-line late last year and is located on the western portion of the middle core, continues to show strong results.

Moving on to slide 10 and looking at the very early data of our extended-reach laterals, we show that we are tracking on or slightly above our 600,000 barrel of oil equivalent type curve to date for both Niobrara and Codell wells. This batch of wells includes both sliding sleeve and plug-n-perf completion methods. I will stress again that this is through less than 60 days. We aren't drawing any conclusions yet, but are pleased with our team's ability to drill and complete these wells without issues. We'll continue monitoring the performance over the coming months.

As far as plug-n-perf, we have updated the graph shown at Analyst Day in April. You can see here on slide 11, that we are experiencing a sizable uplift through the better part of a year with these wells. To date, we have performed 16 plug-n-perf completions including 12 on extended-reach laterals. The vast majority of our tests do not have as many days to analyze. As a result of that, we have not concluded any uplift associated with plug-n-perfs in either our updated guidance or our three-year scenario that Lance will touch on in a few minutes. We have 39 plug-n-perfs planned in the second half of 2015. Whereas the plug-n-perfs cost approximately $100,000 per well and require a bit of logistical planning, the AccessFrac completion costs roughly $50,000 and can be done more on the fly, if you will. Again, through relatively early data, we are seeing an uplift associated with the BioVert completion method compared to our standard completions. We have used BioVert on approximately 17 wells to date and will continue to evaluate our current results and conduct more tests in the second half.

Moving to midstream on slide 13. As you know, the Lucerne 2 plant came online at the end of the second quarter just a couple of weeks behind schedule. The facility continues to ramp up to its full capacity. We have seen field-wide line pressures decrease over the last month. Pressures have come down nearly 60 PSI with potential for further reductions as equipment run times improve. As a it currently stands, the field-wide system is expected to have excess capacity in the short to mid-term, though it is too early to tell how much and for how long. There are two things important to note here. First, our internal model did not account for any uplift associated with Lucerne until the third quarter. Second, the majority of our wells including our extended-reach laterals flow through OCCA energy's system. In the Utica, we successfully turned-in-line the four-well Cole pad. After a couple of minor hiccups got a solid month of flush production in the second quarter. The Cole was completed very similar to the Dynamite pad from earlier in the year and like the Dynamite has exceeded our 680,000-barrel of oil equivalent type curve thus far. We are done for the year in Utica, but the results of both the Cole and Dynamite pads have really increased our confidence in the play. We are excited to get back to work when the time is right.

So to recap the quarter on slide 15: we achieved record horizontal turned-in-lines in the Wattenberg; have produced record oil volumes and a record percent oil; turned-in-line our first batch of extended-reach laterals in the middle core of the Wattenberg Field with strong initial results; had a key midstream catalyst startup of which we are already feeling the results; have moved a little closer to verifying our confidence with new completion methods in both basins; and have once again delivered results exceeding our type curve in Utica.

So shifting gears, we'll spend the next couple of minutes discussing our updated guidance from an operations standpoint starting on slide 16. Here you can see graphically the increasing drilling efficiencies in terms of footage drilled per day. You can see an increase of 30% from the speed in which we were drilling last year to what we are currently achieving. There are several reasons for this. The new ADR rigs are similar to -- are able to minimize down time. Our teams are really hitting their stride and working incredibly hard. Lastly, we've incorporated some analytics that have helped. What this corresponds to is an average drill time of 10 days for standard-length lateral, with some wells having been drilled, spud to spud, in as little as seven days. As Bart mentioned, due to these rig efficiencies, we are able to go to four rigs and not sacrifice any of our previously planned spud count.

On slide 17, we show that we are increasing our production guidance range up to 14.7 million to 15 million barrels of oil equivalent from the previous range of 13.5 million to 14.5 million. Our new range reflects approximately 60% growth over continuing operations from 2014. On the last call, we mentioned we had been experiencing higher working interests, reduced non-consents and faster drill times, all of which are incorporated in this new guidance range. This obviously contains actual data through the second quarter. In July, we've had an additional 18 turned-in-lines. One of the main drivers of our production growth relates to the strength of our position in the core Wattenberg Field.

Slide 18 shows our internal rate of returns updated. Previously, our internal rate of returns were run at $60 oil and $3.25 gas held flat forever. As you can see here, using the July strip pricing and adjusting our well cost to reflect the current costs we're receiving, our internal rates of return remain strong throughout our leasehold. As a reminder, our 2015 and much of our 2016 programs are focused on the inner and middle cores.

In terms of capital, you can see on slide 19 what we have spent through the first half of the year and our new expectations for the second half of 2015. Obviously, the trend shows that we are slowing down from a capital standpoint in the second half compared to the first half of 2015. The main contributors to this are reduced well cost and reduced levels of non-consents and non-operated drilling. Total capital for the second half is estimated to be between $203 million and $233 million.

Moving on to LOE on slide 20. We expect our full year lease operating expenses on a BOE basis to come in under $4. As you may recall, we had a $3 million one-time charge in the first quarter associated with a couple EH&S regulatory and compliance measures. The second quarter saw a nice decrease in our LOE rate. We expect that trend to continue as we continue to grow our production base.

To sum up our reguidance. Production has increased and expected to be between 14.7 million and 15 million barrels of oil equivalent. Operated well spuds and turned-in-lines increased to approximately 155 and 125 from 119 and 109. We are still planning 47 extended-reach laterals for 2015 and a 75/25 split on Niobrara and Codell wells throughout the entire program. Plug-n-perf and BioVert uplifts are not included in any forecasted volumes. Drilling times reduced to 10 and 12 days for a standard reach lateral and an extended-reach lateral respectively with a potential downward bias. Our well costs have continued to decline and now sit at approximately $3.1 million and $4.1 million for standard and extended-reach lateral.

I'll now turn the call over to Gysle who will cover the financial details for both the second quarter and updated guidance.

Thanks, Scott. Good morning, everyone. Glad you could join us. As always, my comments will be high level. So for a more complete analysis of our second quarter, please see our press release and 10-Q that was filed this morning.

As you've heard, our first half of 2015 had lots of activity in Wattenberg. We turned-in-line our four-well Cole pad in Utica. Production for the second quarter was 3.4 million barrels of oil equivalent. That was right at our expectations. It's worth mentioning that production could have been more than 240,000 barrels equivalent higher if weather in Colorado hadn't delayed several turned-in-lines during the quarter. Our second quarter reflects continued success for both programs with record production for PDC in the Wattenberg as well as a new high in Utica. Despite much lower commodity prices, we still saw growth year-over-year in adjusted cash flow from operations and adjusted EBITDA, aided by our hedge position with $44.1 million in realized hedge gains in the quarter. That's the high level summary.

Now let's get into some of the metrics for the second quarter. Again this quarter, year-over-year production increased over 45%, while our second quarter oil and gas sales were down 26% compared to the Q2 2014. Oil, natural gas and NGL prices all declined year over year and quarter over quarter. Crude oil prices for the second quarter of 2015 averaged $48.31, down 47% from the second quarter 2014. Average natural gas prices were down 52% from the second quarter 2014 and natural gas liquids were down 64%. When we factor in our realized hedges, however, total sales plus realized hedges were up approximately 16% over the same periods. The net realized hedge gain of $44.1 million this quarter compares to a net realized loss of $9.8 million in the second quarter 2014 and a net gain of $50.4 million in the first quarter 2015. Production costs on a per unit measure were down about 38% year-over-year. Production costs include lease operating expense, production taxes, overhead and some transportation and processing costs in Utica. For the second quarter 2015, we averaged $6.38 per barrel of oil equivalent, down from $10.30 per barrel of oil equivalent in the second quarter last year. Gross margins were 78% of sales in the second quarter of 2015, down slightly compared to 82% for second quarter 2014, reflecting the big decrease in commodity prices, nearly offset by a strong decrease per BOE in total production costs.

Moving to slide 24, we show our non-GAAP metrics. I want to point out the reconciliation to GAAP numbers in the appendix. Our adjusted net income of $10.8 million in the second quarter was a sharp decrease compared to the $1.5 million loss in the same quarter of 2014. Adjusted cash flow from operations is defined as cash flow from ops excluding changes in working capital. Adjusted cash flow for the second quarter was $96.9 million or $2.42 per diluted share, compared to $55 million or $1.54 per diluted share for the second quarter 2014. Adjusted EBITDA in the quarter was $101 million, up significantly compared to the second quarter 2014 of $62.7 million. Adjusted EBITDA per diluted share of $2.52 was also up significantly year-over-year from $1.75. DD&A includes depreciation of fixed assets and depletion of oil and gas properties. Per BOE, DD&A decreased year-over-year due to last year's Utica impairment and the increase in comparable production. Per unit depletion rates on just oil and gas properties for the second quarter was $20.48 per barrel of oil equivalent, compared to $21.05 per barrel of oil equivalent in the second quarter 2014. We expect these rates to continue to increase throughout the year with lower drilling and completion costs. G&A decreased in the second quarter of 2015 compared to the second quarter of 2014, largely due to a $20.8 million litigation charge last year. G&A excluding the litigation charge decreased 31% on a per unit basis to $5.55 per BOE in the second quarter from $8.06 per BOE in the second quarter 2014.

The table on slide 25 reflects PDC's borrowings. We began the second quarter with $67 million in cash following the equity offering in March. We guided to first half of the year waiting for CapEx and as of June 30, 2015, we were drawing $53 million on the revolver. We expect to be cash flow neutral in the second half of 2015 and exit the year drawing less than $50 million. Our trailing 12-month debt to EBITDAX as of June 30 is approximately 1.8 times. As Bart mentioned, we expect to end the year closer to around 1.5 times. With our $700 million borrowing base net of $12 million letter of credit, we have $637 million of liquidity as of the quarter end. We have a redetermination of our borrowing base in November and are waiting to see what price decks the banks will be using before we can guide you on the outcome. Our $115 million convertible notes mature in May of 2016. While we don't have to make a decision until later this year, in our outlooks we've modeled retiring the face amount in cash and using common stock for any value above the $42.40 convert price.

On slide 26, our hedge positions for the balance of 2015 and for 2016 and 2017 are shown on this page. As of June 30, our net hedges are valued at $223 million. We are substantially hedged for crude oil and natural gas production volumes for the balance of 2015. For the second half, we have about 72% of our expected crude oil volumes hedged at a weighted average price of $88.99 per barrel. On gas, we have about 72% of expected volumes projected at a weighted average floor of $3.74 per MMBtu. Our hedge coverage on a percent basis dropped a little from our last report due to higher production expectations for the remainder of the year. For 2016, we have 4.1 million barrels hedged at weighted average floors of $84.99. For natural gas, we have 29.8 Bcf hedged at weighted average price of $3.71 per MMBtu. We have some good volumes hedged on natural gas for 2017 and have about 1 million barrels hedged in the same year.

Bart and Scott walked you through increases in production and guidance, so here on slide 27, we have updated financial metrics based on that production. The teal column in the middle of the table shows our guidance from Analyst Day in April, which was run at $51.72 for oil and $2.86 for gas, with NGLs priced at 31% of NYMEX crude. The copper column shows our new guidance ranges starting with production on the top line. For our updated guidance, we used actuals for the first half and then forecast using the end of July strip. As it turned out, the updated strip price is very close to our original full-year expectations. Oil is down $0.51 to $51.21. Gas is down $0.03. We reduced our NGL expectations down to 19% of NYMEX for the second half of the year, which is about 3 percentage points less than what we realized in the first half. The main numbers to look at here are adjusted total revenue, which is up about $30 million on the high side of the range, as is adjusted EBITDA. On a per share basis, we're up about $1.10 on cash flow and about 10% on adjusted net income when we compare to the high sides.

With that, I'll turn the call over to Lance.

Okay. Thanks, Gysle. On slide 29, we show an updated three-year outlook for the period 2015 to 2017. That's the focus of this final section of our presentation. The purpose of this update is to reflect several recent changes, not only the efficiency gains and cost reductions as highlighted by Scott earlier, but also to factor in the reduced NYMEX commodity price outlook. So at our Analyst Day in April, we provided a base case three-year outlook. Those assumptions are shown on the left side of the slides. Today, we're providing an updated base case outlook. Those assumptions are on the right side of the slide. So starting with the price assumption. At Analyst Day, the strip for NYMEX ranged from about $52 a barrel in 2015 to about $61 per barrel in 2017. Today, the strip prices range from about $51 to $56 per barrel in 2017 or about $5 per barrel less in both 2016 and 2017. Gas prices are similar for both periods.

Now let's take a look at the rig pace and the spud counts for Wattenberg. At Analyst Day, we projected a five, six, seven Wattenberg rig pace from 2015 to 2017. Given the increased efficiencies, we anticipate now that we'll drill approximately the same number of wells over the three-year period of time using a four rig pace in 2016 and a range of four to five rigs in 2017. The big improvement is seen in the number of wells each rig drills per year. In April, we projected each rig at about 25 wells per year. Today, due to our rig efficiencies, we project about 35 wells per rig per year. As Scott talked about earlier, operating teams continue to drive down completed well costs in the Wattenberg Field. Our standard-length lateral is now projected at $3.1 million, while the extended-reach lateral is now projected at $4.1 million. So despite the lower NYMEX price outlook that we see today, our cost reductions enable us to still project approximately 30% to 60% rates of return in the inner and middle core areas as was shown on slide 18. This continues to demonstrate the resilience of our core Wattenberg portfolio.

At our Analyst Day, our base case projected a return to drilling in Utica in mid-2016. However, from where we sit today, given the current lower NYMEX price outlook and persistent large gas differentials at TETCO M2, our base case outlook only includes three wells in 2016. These three wells are anticipated to be drilled in the condensate window fairway of our core southern Utica acreage in Washington County, Ohio. The improved completion designs on the Dynamite and Cole wells in Guernsey county will be utilized on this three-well pad. This test will provide much needed long-term production and reservoir data for our southern acreage in the Utica Shale play.

Now let's look at slide 30, the base case outlook results. This slide provides a side-by-side comparison of the three-year base case outlook from Analyst Day, to that of our updated base case today. So before I talk through the results, I want to highlight a couple of key points. First of all, our outlook projections for 2016 and 2017 represent our current base case outlook and they are not our guidance for those years. These projections are based on several assumptions that we see today. As most of you know, our formal 2016 budget process will begin later this fall with a planned target release date sometime in December. Also like Analyst Day and as Gysle touched on as well, we assume that the principal amount of our 2016 convertible notes are paid in cash, which is approximately $115 million and any additional value above the $42.40 convert price is paid in shares.

So let's start first with production. Our updated base case now projects a three-year compounded annual growth production rate range of 34% to 38%. That's up from 31% to 36% as shown at Analyst Day. In 2017, we still project a midpoint production of approximately 60,000 barrels of oil equivalent per day net. On the capital spending side, our updated base case is now projected to be reduced by over $200 million for the three-year period of time. That's at the midpoint projections. All the while, still delivering the same 60,000 barrels of oil equivalent per day net in 2017. We anticipate that our combined cash flow for the two-year period of 2015 and 2016 will be very similar to that as at Analyst Day. Our updated 2017 cash flow is projected to be approximately $75 million less than Analyst Day, due to lower NYMEX commodity price outlook and the reduced capital spending in Utica. So if you look at both the capital and cash flow graphs side-by-side, you'll see that in our updated case for 2016 that we project that our spending will be approximately equal to cash flow based on where we sit today with our current modeling a assumption. Our updated base case projects a 2016 year-end debt to EBITDAX of slightly less than 1.5. Our 2017 year-end debt to EBITDAX projects to be approximately 1.6 to 1.7, down from that of Analyst Day at 1.7 to 1.8. So to summarize, we anticipate approximately 35% production growth in 2016 with a capital spending equal approximately to cash flow, based upon our current assumptions.

Finally on slide 31 of our presentation we want to provide an update to our estimated differentials relative to NYMEX. The purpose of this slide is to show what's changed since Analyst Day and how we're now modeling our differentials not only for the second half of 2015 but also for our outlook cases of 2016 and 2017. The biggest change is in the price of our NGLs for both Wattenberg and Utica. These declines are due to the current oversupply faced by the industry. For Wattenberg, we now project NGL prices at 16% of NYMEX crude, while Utica is now projected at 25% of NYMEX. Gas netbacks in the Utica are now projected lower due to the continued oversupply at the TETCO M2 sales point. We now project Utica gas netbacks at about 62% of NYMEX. Finally, we now project that our long-term crude oil differentials for Wattenberg will be approximately $9 per barrel. That is an all-in number NYMEX to well head. That's due to given excess capacity take-away from the field. This differential was about $10 per barrel, but we're seeing it come down to around $9 per barrel. Very recently, we sold some incremental barrels inside of that $9 per barrel. So that's our overall updated pricing summary.

So with that, I'll turn it over to the moderator for Q&A.

(Operator Instructions)

Mike Kelly, Global Hunter.

First off, I've got to applaud you for probably having the most thorough update of any E&P this earnings season, here. Nobody really wants to talk about 2016, let alone an updated three-year look. So this is great.

I did want to touch on just a couple things. One, just with the outlook here for 2016, if you could give us an oil and gas split? I apologize if you mentioned that.

Right.

So Mike, what we look for in 2016 is we're going to be bringing in a significant number of turned-in-lines from our inner core area, where we have a very significant amount of gas production from those inner core wells. So we look for our percent oil mix to go down a bit in 2016 as those big inner core wells are coming online.

Keep in mind, the inner core wells have a much higher rate of return, so the economics are extremely strong. So that's a positive story. Then if you look back at 2017, what we see is that oil mix coming back up some because we'll be concentrated in the middle core areas, and to a lesser extent some into the outer core.

Okay.

As far as having the actual percentages, no, we'll have that when we release the end of December our actual budget numbers for 2016.

Mike, this is Bart. Is it fair to say that we don't expect more than a couple points swing in the oil. When we talk about it getting maybe a little gassy, we're not talking about significant shifts in the overall percentages.

Right. The overall crude is projected probably in the low 40%s for 2016. Overall, the liquids percent, if you add in NGLs and you add in crude oil with that, you're going to find it's approximately that 63%, 64% type percent.

Okay. Great. Appreciate that. It does look like -- I wanted to talk about the results you're seeing on your extended-reach laterals in slide 10, where you put the actuals up against the 600,000 type curve. This does look like it's a mix of the plug-n-perfs and the sliding sleeves. I was curious, given what you're seeing on the plug-n-perfs on the standard-length laterals, how -- if you wanted to isolate how these plug-n-perfs are looking on the extended-reach? If you could potentially -- I'm trying to get to, could you potentially see a 30% plus uplift ultimately on the 600,000 curve here, ultimately giving you some upside there? Thanks.

Mike, I think we can speak to those a little bit. Part of what we were faced with there was some of the start-up associated with OCCA. So we haven't had really the ability to test the extended-reach laterals in relative terms between the plug-n-perf and the sliding sleeve. So it's a little early for us to make -- draw a conclusion on that. As far as whether our expectations are any different from the standard laterals, I don't see it being a lot different at this point.

Really, that effect that we get from plug-n-perfs on standard laterals should be very similar on extended-reach laterals. We should be contacting more rock giving us the opportunity to create additional production. Like I said, really, we'd need about another couple of months. I'd say two or three months, well start to get past some of the startup issues we were faced with on OCCA. They weren't extreme. They just limited our capacity to actually produce the wells consistently.

Okay. Great. Just clarifying point from me, I think you mentioned in your comments here that the 30%, the 35% improvement in the plug-n-perf and some of this BioVert upside, that's not being dialed into guidance right now; correct?

That's correct. We do not have that in there. We'll be looking at that towards year-end, as Lance pointed out in our budget to decide how we're going to deal with that.

We're still very early in these tests. We're obviously very excited. We're showing you the data that's really early. But we're very excited about where we're headed. It's just really early to put all that in an expectation for this year and next year.

Okay. Thanks a lot. Great update.

Pavan Hoskote, Goldman Sachs.

Appreciate the updated 2016 outlook. You talked about growing production 35% while spending the new cash flow. Want to dig a little deeper into some of those assumptions.

One, how many wells do you expect to turn-in-line in 2016 versus 2015? Then second, are there any key midstream projects that will be needed for you to hit the number? As a result, should we expect production to be lumpy in 2016? Or will it be a more steady ramp-up to 2016?

So yes, when you look at the trending lines for 2016, we are projecting around the 160 to 165 range for the Company next year. Keep in mind, I think we have as far as carry-in wells from 2015 into 2016, we have close to 60 to 65 operated wells that will be carried into 2016. So that gives a strong support for the growth in production, therefore, for 2016.

Got it. Anything on the midstream projects?

As far as midstream, we don't have any assumptions in the 2016 model as far as additional capacities coming online. We obviously have our OCCA development that will continue in the inner core and the inner middle. Then DCP right now with the startup of the Lucerne 2 plant has sufficient capacity, we feel. And based on the rig counts in the basin, we really feel like DCP most likely is heading into 2016 with sufficient capacity for our production. So we feel like we've got a pretty good handle.

As we go through the balance of this year, we're going to be able to really evaluate the overall impacts to our production due to lower line pressures and build that into our 2016 guidance. As Lance noted, that's a process we'll really hunker down on in September, October of this year.

Then the last component of this that's really going to help our oily production in the northern part of the Wattenberg Field is the Grand Parkway line, which is a significant project. It's a large diameter, low pressure line that is going to pull the field pressure in the very northern portion of the Wattenberg Field down, we think starting at the end of this year and should be a nice contribution, particularly to our old oil wells in the northern part of the field. So we've got several things that are happening, but overall, we feel like there's enough midstream as we start the planning process for 2016.

Great.

Then an unrelated question, can you update us on your latest thoughts on M&A? You're obviously growing production at strong levels organically. But given strength in the system, do you see acquisition opportunities in either the DJ Basin or even outside the Basin? But more broadly, when you evaluate acquisitions, what metric do you use to evaluate acquisition opportunities versus growing organically? Is it in a [REIT] per share accretion metric? Or debt-adjusted growth, or some other metric?

Okay. So overall we see the A&D market as something that will probably heat up more in the fourth quarter moving into 2016. A lot of that's the function of what crude oil prices do and as far as access to capital for some of the other companies. From where we sit today, our three-year outlook is just organic only. It delivers a very robust growth as you can see in production and cash flow. So our focus is on organic.

As far as PDC itself, for us to bring in an acquisition as you mentioned in the DJ Basin, it would just have to be something that would be very stellar, something that would really add a lot of value to the Company. We have such a long inventory of wells to drill. We have 15 years of drilling inventory plus within the basin. So we're sitting in a very good spot from that standpoint.

We do continue, though, to research and look at various basins around the US onshore to look for those opportunities where we could find an acquisition that could make sense to the Company, something that our operating teams could add a significant more amount of value to it. So we're doing that work. We're just really getting started on that. So that's something that we're focused on but it's nothing that is something that we feel is any time soon as far as reaching any conclusions with where we might go with that.

As far as metrics and how you look at acquisitions, there's lots of different metrics that you look at on that. But the key thing we want to look at on anything we do is to be accretive to our metrics. That's really the focus that we have. It's something that we can add a lot more value going forward from that asset package that we'd acquire.

Got it. Thanks a lot.

Irene Haas, Wunderlich Securities.

A question for Lance. How long do you think this NGL glut would last? Secondarily, production in Utica, should we expect it to decline in 2016? How long you would want to sit out? It looks like you're not going to put a rig to work in 2017. So maybe just a little color on that, please.

Sure. Good question, Irene.

As far as the NGLs go, we are projecting sort of the 17% plus or minus price for Wattenberg to last through 2017. Maybe that's a slightly conservative approach to it, but there's a lot of oversupply. We feel that from where we sit today that's sort of the range that we want to look at. That's what we put into our models going forward. We hope that we have some good crop drying season. We hope that we have a very cold winter for usage for specifically like for propanes and all. But it could last a little while. So that's what we factored into our outlook going forward.

As far as the Utica, you're correct, the Utica will be on decline, a slight decline from 2016 versus 2015 and then 2017 versus 2016, because all we have in the three-year outlook is the drilling of the three-wells in Washington County next year. So there will be some decline in that area. I think the good news though for us in the Utica is that we're really getting that condensate fairway with this test. I know our operating and geological teams have done a lot of work in finding this specific location. We think the long-term value that it will bring from both long-term production and reserve data will be very beneficial to the Company.

Great. If I might ask one more question. Where do you sell the condensate? Is that a local kind of thing because you got really great netback for it.

Yes. So the condensate is sold locally; that's correct.

Great. Thank you.

Neal Dingmann, SunTrust.

Bart, just looking at that slide 11 and 12, it looks like going forward for the second half of this year, and I think you were talking to 2016, you're still looking at the plug-n-perf versus the AccessFrac. Maybe just talk a little bit about it. You're just looking for more tests to decide -- I guess what I'm trying to figure out, Bart, is it more on the inner core? Or geologically on how this works in certain areas? Or, again, what do you expect to find by the end of this year? Will one be the predominant way? Or any color you could talk about one versus the other?

This is Scott. I think I can answer a lot of your questions. We're asking many of the questions you're asking yourself even yet as we go through this process of understanding what happens. I think when you look at the plug-n-perf, it's been done across the field in a number of different areas. The testing has been done that way. So we're starting to get a feel across the geologic variations that occur, the different GORs that occur.

In addition, when you look at that compared to the BioVert AccessFrac process, we've done those two independently at this point. We are looking at a test to combine the two. It's something that our teams are working on the proper design for that as we speak.

So really when you start talking about how we're doing this, we're still in those phases of understanding it. That's why we struggle yet to say we're going to put that in our expectations for the second half of this year and into next year. When you combine the two, we'll see what happens with that. But that will be really interesting to us to see if we can see the uplift in both of those.

As far as how we're doing this right now, we do have a pretty significant count of both of those types of tests through the end of the year. We're looking at somewhere near 40 plug-n-perfs and something on the order of 35 AccessFracs through the rest of the year. So it really tells you, there's quite a few different approaches we're going to be taking. It's something that like I said, we're very excited. We feel like we're learning a lot as we go along. We're learning much of what the questions you're asking; how does it look geographically and across the various GORs and geologic parts of the play.

Scott, do you anticipate seeing anything as far as just the depletion on that? Or do you think more of what you're looking for is in the initial months on this? Or is it on both?

To me, and again, I don't think it's really going to be anything associated with depletion. It really is a matter of, can we contact the rock in all these different areas enough to make a difference. When you move into the gassier areas, are you already getting the production? Or is it something as we add the AccessFrac or the plug-n-perf, are we contacting more rock -- more rock that wouldn't be depleted under normal circumstances. So, it really comes down to that type of approach. We're talking about all those different tests for the reasons of understanding it at this point.

Makes sense.

Then just lastly, Lance, did you say I guess for plans for the Utica, you have plans for just that one pad in Washington. Will that outcome of that be dependent on any activity? Or at this point, given the economics out west, you pretty much just stick to that one pad next year?

Yes, that's currently, Neal, what's in our budgeting process thoughts there right now, is just to drill that test. We're going to look at the long-term performance of it. The guys have done a wonderful job with the completion designs in Guernsey County.

We're going to take that same completion design down to now in Washington County on that three-well pad and just look for some long-term performance data from that. As you know, Neal, we've got a lot of acreage in that southern Utica play. That's going to be very helpful to us as we think about what the play will ultimately develop for us in that northern Washington area.

That makes sense. Thank you all.

Brad Carpenter, Cantor Fitzgerald.

Congratulations on the great update. I had a question on slide 29. Lance, you did a good job of walking through that. But I was curious, to what extent if any does the new base case reflect a shift towards the resilient case? Because you used to show that as $50 flat NYMEX crude for 2015, 2016, 2017. As we're approaching that on the actual strip, I was curious how much of the new updated base case reflects merely efficiencies and cost reductions? How much, if any, reflects that shift towards the resilient case?

Well, as you'll recall, back at our Analyst Day, our resilient case was a keeping rig pace flat. It was also of a $50 oil. I believe it was a $3.25 price per MMBtu. This case isn't too far off of what I would say would be a resilient price. I mean, the fact that we get out to 2017 and the crude price is still just $56 per barrel.

So you look at the price, it's something that we would say would be fairly resilient as far as the price goes. When you look at the fact that we're dropping the rigs next year to stay at four-rig pace, it gives us the opportunity to really watch crude prices throughout 2016. We've got tremendous optionality to make adjustments based upon what we see for crude prices next year.

If I could add one thing to that. I think the other thing that we're reflective of is definitely that reduction in cost that we didn't show in our initial assessment. So the costs have come down and help support, obviously, the continued development pace.

Okay. I appreciate that. Then Bart, in your prepared remarks you said you'd increase activity in the Utica when the time is right. You've kind of touched on it throughout the Q&A session, as well. But looking at that 2017 base case in the Utica with zero spuds, what would deem the right time for an increased activity in the Utica? Is it merely price and differentials? Or is there enough room on improvements in reductions in cost that can get you there and we could see an increased spud activity at the current pricing?

Yes. It's a good question. First, let me just step back and tie back to Lance's comments a little bit. This is a play right now, we couldn't be more pleased with the resource potential, in that we now, with our new completion designs think we have a pretty firm number of 700,000 to somewhere around 1 million barrels of reserves per well. So, the first part of your question is, we've got to have our cost structure probably more competitive in today's market.

So our team's working diligently on that. We think we have a drilling and completion per well cost down around $7 million. Maybe even some indications the number could drop below that $7 million. So that's how quickly the cost structure in Utica has moved.

Then the second part of your question is, we've got a triple whammy right now going on, on the pricing, on the commodity pricing side. Lance touched on NGLs, how much they've deteriorated across the whole country. But that's a component of our revenue stream here. It's disappointing what those are currently moving for. When you net the NGLs against the midstream costs, there's not a lot of margin that we have coming back to the bottom line for the Company.

Then you have natural gas which has over $1.50 into differential right now. We've got to find with our marketing group a way to try to minimize the impacts of the oversupply in the east on the natural gas side.

Then on the oil side, we're going to need a slight rebound. We're going to need at least probably a $6-handle. I think we've been out in the market saying we'd love to have $60 plus to really buoy the Utica play for us. I think, Brad, we're going to need a few of those things all coming together, maybe a slight rebound in oil price, some really strong marketing efforts on our gas marketing team, and then our operating team really pushing on the cost structure. I can tell you this, we're working on all of that to try to get this thing kicked off again. But we're not going to do that until we have clear vision long-term that this thing can at least compete with the outer core of the Wattenberg.

Okay. That's very helpful. I appreciate that.

Then a real quick one just for modeling purposes, could you remind us when Chesnut and Churchill went to sales during the quarter.

It was really right at the tail end. I mean the Chesnut wells started coming online in April, May timeframe and really the Churchills were in the June and even into July, the first -- the last of the Churchills started coming online. So they were really scattered across that time period.

Okay. I appreciate that. Thank you much.

Ryan Oatman, Cowen Group.

At the April Analyst Day presentation the base case implied 31% to 36% for semi-annual growth through 2017, CapEx rising from 2015 levels. Looking at this new plan, it looks like essentially comparable 2016 to 2017 production despite less capital. Understanding that you haven't included uplifts from plug-n-perf or BioVerts, what's driving that higher productivity? Is there any way you can sort of allocate or quantify between, say, infrastructure improvements, new completion designs, cost savings?

Yes, Ryan. When we look at the production growth that we have, a lot of the growth that we have, first off for 2016 again is a big number of carry-in wells are going into 2016 versus that of 2015. We've focused a lot in the inner core area for drilling in 2015. A lot of those will be some of those carry-in wells. So that's part of the growth there in 2016 that has going forward with that. So when we look at our production growth across the board here, we see that we continue to improve in how we continue to drill and complete our wells.

That said, we haven't included any of the BioVert or the plug-n-perf in these numbers. So it's something that is very comparable, very close. Keep in mind, it doesn't have as much Utica production in it. But with the lower cost per well, we're able to get more wells drilled. At the end of the day, we're drilling about the 450-well pace in this new plan. That's what we had for Analyst Day. If you look at how those 450 wells are drilled, it's moved up towards the first few years, 2015 and 2016. So you've got more of those 450 wells toward the first couple years.

That's helpful. Then can you -- speaking of the Utica, just remind us of your leasehold requirements there? The land position?

We have currently around the 65,000 net acres in the play. Where we sit, Ryan, is that for 2016, we have almost no lease renewals there. So no costs there. For 2017, we have, I believe, it's as much as $30 million in primary term leasehold renewals. The benefit of drilling this three-well test next year will give us the ability to determine if we want to spend all that amount or maybe a portion of that amount.

Got it. That's helpful.

Then on the guidance front, Gysle, looking at the expectation for, I believe, it was $50 million to be drawn on the revolver at year-end, I assume that forecast the converts are retired in May 2016. I understand the holders can elect to convert those prior to mid-November. Can you just speak to that a little bit?

Sure, Ryan. We have not seen or seen any requests at all to convert early and that would be pretty typical for a convertible note. They're getting a little coupon and then they're in the money. Wouldn't expect to see a lot. But you are correct, in 2016, we assume that we just swap revolver debt for that convertible debt, which is a net neutral on the metric in 2016 and 2017 and just goes to shorter term maturity. So really not a lot of change overall to the debt -- to leverage metrics or debt metrics as a result of the conversion.

Make sense. Thank you.

Brian Corales, Howard Weil.

Looking at the long-term development, I think maybe you talked about having a -- deciding on a completion factor or a completion method in 2016. Did I hear that right? Or can you maybe just talk about plans for going forward? When you're going to decide on what's the best method for the cost? Can you also maybe talk about percentage of extended laterals in the out years, as well?

Brian, I can talk a little bit about where we're headed in terms of completion methods. It's a fairly complex puzzle yet for us in terms of exactly how we do all this. For next year, you can see, though, our confidence is building. We're actually ramping up the second half of this year with more of the BioVert and more of the plug-n-perf. So that gives you some indication of what our thoughts are.

In terms of going into next year, I think we'll be taking into consideration a lot more data than we have today. Obviously these are very young projects in terms of their production. But I really think around budget time Bart's going to expect us to have an estimate of those costs and what we're going to roll into next year. I think our teams will be very able to do that.

At this point my expectations are we're going to have a fairly significant number of BioVerts and plug-n-perfs. Really what we won't know at that point, because we won't have a lot of data is, do we stack them on top of one another, do we do both of them on a single well bore.

Brian, on the second question with regard to percent extended laterals, Wattenberg in the out years, we're projecting in the range of 25% to 30% of our spuds being extended-reach laterals.

Just is that because of the acreage? Or is that because you're still testing it out a little bit?

Well, I think the main part of this is as you go further and further out in the future, we don't have as much visibility around the units that we're putting together, say a partner or ourselves as far as how many we're going to find with the capability to drill extended-reach on. So there's less known as you go further out in the future, but still for 2016 and 2017 we're in that 25% to 30% wells extended-reach.

Brian, for me I don't see this as a question as to whether we need to test the extended-reaches any further. I'm getting fairly confident that they're going to perform. It really is -- it comes down to the acreage position like Lance was describing. I think that's still something as Lance said, it's a challenge for us to know too far out in the future.

Thanks. Appreciate it.

Ipsit Mohanty, GMP Securities.

A lot of them already answered. But if I could just -- looking at quarter-over-quarter, it seems like your oil lead improved. Now was that a function of more middle core wells coming along? At Analyst Day you probably provided for a 45%, 46% oil lead for year 2015. Does that still stand?

In terms of the quarter on quarter numbers, we definitely have seen that, as you pointed out, the oil come up. We really see that being stronger for a couple reasons. For the first half of the year, it really was a function of some of those turned-in-lines. I also think our non-operated production is more oily than what we have projected at the first of the year.

Then going in the second half of the year, we have expectations that our older wells, the ones that are more influenced by the higher line pressure will come on and those have a lower GOR overall. So really it's a combination of those three factors, that will push that oil level up.

Okay. So you're going to maintain that full-year production number, I believe, of 46%? Or is it going to go up?

I think there's going to be a slight upward pressure on it, but I don't think it's going to be significant. It might go up 1 point, something like that. So really in the range you're talking about, that 46% is probably a pretty good number.

All right. You mentioned about in your prepared remarks in your release about your working interest going up. What's your current operating working interest? How do you see that in your guidance in 2016 and 2017 in the Wattenberg?

I'll speak to the 2015 numbers and then I think Lance will jump in for 2016 and 2017. The first half of the year, because of the non-consents and the really some small trades that we did, our working interest percentage was in the middle 90%s for percentage. When you move into the second half of the year, we're expecting that because there aren't -- we're not really expecting non-consents and the trades are such that there will be a small number if any, we're really looking at something that's probably in the middle to low 70%s in terms of our working interest for the second half of 2015. I think I'm going to let Lance jump in on what he has projected for 2016 and 207.

For both those two years, 2016 and 2017, our models project approximately a 75% working interest.

Ipsit, we anticipate that as we go through the balance of this year and next year that our peer operators are really gaining an understanding of the basin economics and that they will be partners in our projects. At least our discussions with them, we had a series of non-consents come our way. It probably caught us a little bit -- surprised us a little bit but as we're going through the balance of this year and into next year, we anticipate that they will join us in our drilling projects.

Thanks, Bart.

My last one. I look at your slide 18, I compare it to what you had provided in Analyst Day. I think the IRR spread between your normal and extended laterals has widened a bit. For example, between the middle core extended and then standard and extended, middle and standard inner core. Is that a function of commodity prices? Could you explain that a bit?

I think I can do that some justice. It really is a function of that price bio like you said, where we're at really at the strip price today. I think in addition to that, our price reduction in terms of our capital costs, percentage wise isn't exactly the same in terms of percentage on the $3.1 million and $4.1 million. That combination is really what's creating that disconnect between the two. We really look at that and say we're still delivering very solid rates of return. The PV10 value is such that we're still very excited about the longer lateral, that type of thing. So we still feel like we're delivering tremendous rates of return for our investors.

All right. Great quarter. Thank you.

Mike Scialla, Stifel.

Scott, you mentioned the Sunmarke pad doing better than expectations. Can you add a little color to that? Also wondering as you look forward, are you planning on using 20 wells per section? Or are you sticking with a number lower than that?

As far as the performance of the Sunmarke, I would say it really is performing at our expectations, based on the downspacing, you could have some expectations you get something less, and thus far we've not seen that, Mike. We're still very early. You can imagine that the impact of 20 wells per section could be a little later in the life of the well versus early because of that near well bore flush that comes off early in the life of a well. So we're pleased with what we see on the Sunmarkes at this point and like where we're headed there.

As far as where we're going in 2016, that's yet to be determined. Some of those wells are already permitted for early 2016. So we're not going to get to make a shift on those. So some of them will probably be at 16 wells per section and some, obviously, spaced greater -- with greater wells per section than that. It really will be in the second half of 2016 that we'll be looking at what changes can we make. It will probably be fairly late that year just because of the time that it takes to get the new permits.

So as far as where we'll settle, I'm not sure yet but we'll have more data. We're still very young in that data set in 20 and above. The number of projects that we have coming online even in the next year is significant. You are well aware of those. But we've got a lot to learn there yet. Like I said, even with the Sunmarke, it's fairly early in the data set.

Great. Thanks.

Then a lot of what's driving the numbers here seems to be much faster than anticipated drilling. You mentioned the benefits of the ADR rigs. Anything you've changed in terms of the drilling techniques? I know one of your competitors is out there talking about drilling without using an intermediate casing string. Just wondering if you tried that? Or if that's part of your plans at all.

Like I think we've all said, we're extremely pleased with where we are in this whole process. We're young to those ADR rigs. We've only had them for a couple of months. So the idea that we've gone from 14 to 10 over this short a period of time, in terms of days spud to spud is an extraordinary event. In my career you don't typically see this. In terms of the approach we're taking, I now our teams are looking at a lot of different sets of equipment, particularly -- also it's very easy when you get similar rigs to compare rig to rig.

When we talked about the analytics, it's something they're looking rig to rig, with similar rigs we should get similar results. So we're looking at all that combined together is what's really forced it down to the 10 days spud to spud. We do see downward pressure, but we have not taken the step of going to a single well bore, a single string of casing from the surface to TD as some of our competitors have.

We've looked at it some. We like what we see there. But there's some complexities that we need to deal with yet that we want to make sure we don't stub our toe in this process. So I think if it comes down, it will be later this year, early next year where we try a couple of them. Like I said, our teams are looking at that carefully and there's some nuances to that from a geologic perspective that we need to be careful around as well.

Okay. Great. Then kind of a high level question. You obviously have a great hedge position. Any scenario under which you'd think about maybe monetizing those and slowing down the drilling even further? Or slowing down the -- or reducing the rig count, rather, a better way of phrasing it.

Mike, this is Bart. Right now that's really -- obviously we've had discussions and they were pretty short discussions. Our hedges were put in place to protect our cash flow and that's really where we're taking them. I think Gysle mentioned this, I think at quarter end our mark-to-market was $200 --

$223. Call it a net-net.

Currently, obviously with the pricing correction, it's closer to $280. We plan on letting the value of those hedges just come through quarter by quarter. If we were to cash them out and then slow down, we'd obviously free up a lot of cash today. But I think that would probably take away from the 2017 outlook for us, production wise. We gave a lot of outlook for 2016, but we're also spending a lot of time looking at 2017 right now. We are believers that gas prices will probably still be soft in 2017 and oil prices potentially could be very soft also. So we've got all of that strategy that we're trying to manage. With that, we have to continue the growth story but still honor the balance sheet.

Understood. Thanks.

Welles Fitzpatrick, Johnson Rice & Company.

You talked about the working interest assumptions going back down in 2016 and 2017 for the guidance. Can you talk a little bit to any non-op production shifts that moved in that 2016 and 2017 production guidance?

I'll talk a little bit, Welles, about what we see at this point. Then maybe Lance can jump in here and cover the non-operated portion of our expectations out there. We have seen it drop off fairly significantly as the rig count has dropped off. So going from even the first of the year where we really were still -- many of the projects that were done were based on last year's efforts from all of our peer companies. We've seen that drop off significantly going into the second half of this year, in particular the number of projects haven't gone down but our interest in those have. So it's gone down substantially.

So that's why we dropped our capital expectations for the second half of the year from a non-op perspective. It's such that I think as we go into 2016 and 2017, just looking at it from a view of sitting well above the overall picture, if the rig count doesn't pick back up, I don't expect our non-op picture to come up substantially over the next several years.

I think Lance is down here. I'm going to let him speak to what he feels like's going to happen.

So Welles, just as Scott has said there, for 2016 given what the price outlook looks like, our estimates and our modeling shows a non-operated spending in Wattenberg that's very similar to that of 2015. We don't increase that sum until 2017, looking at the fact that at that time oil prices will be a bit higher.

Okay. Perfect.

Then just one last one. Can you guys talk about plug-n-perf and BioVert in regards to the Codell, is that something you've tested? Is that something you want to look at?

We're actually doing it on all of them, Welles. We're trying it on the different zones, even within the Niobrara, the various zones within the Niobrara. Thus far, we've seen -- we're very excited. There may be some differences in the way the Codell performs, but I don't think it will be substantial. At least at this point, it doesn't appear it will be.

But again, I keep stressing, we're young in this process. So we're obviously learning a heck of a lot as we go on. But we are continuing to try these different techniques and all the different options that we have in terms of testing.

That's great. Thanks so much.

Jason Smith, Bank of America.

Congratulations on the really impressive results. Most of mine have been answered. But I have a quick follow-up and then a more generic question. First on the extended-reach laterals, can you just remind us if that's all middle core? Or if you're testing inner core and planning to test outer with those, as well?

What you see on the slide 10 is, these are middle core. They're the Chesnut and Churchills. That's the project that we've had up there for a long period of time on the northeast corner of the Field.

As far as testing it in the outer core, we've had a couple of wells that we've done. They were way up north and have really been faced with high line pressure. But we don't see too much difference in terms of the performance, at least I don't believe we will.

If it's such that I think we can -- we'll do similar in the outer core as what we've done in that middle core. We don't have any plans at this point really to test that, to my knowledge, although things are very dynamic. As we speed up our drilling pace, obviously we pull in more projects. I'm not as aware of possibly as what our team is working on today.

Thanks, Scott. My generic question is I think for Gysle. It's on borrowing base redetermination at the end of the fall. I'm assuming it's not an issue for you, given your growth and your strong hedges. But just wondering generically, any color you can provide on conversations you're having with the banks? What they're focused on? How that -- if that's changed? How that's changed since the spring?

Yes. I think we've had very limited conversations with the banks that give us any specific information. We do know that they're all reviewing their price decks and haven't declared yet if it's going to change from where it was in the spring.

I know we've all heard about the federal regulators starting to look closely at oil and gas loans. My gut feel is, we'll probably see a little bit of a downward adjustment in pricing. I don't think, based on where we are, it's going to have an impact on us.

We've added a lot of reserves in the first half of the year. Our reserves are pretty resilient when it comes to pricing. You saw that in our year-end sensitivity analysis on our reserve report where we reduced prices and showed what the impact to reserves were. So I don't really have a good answer for you other than we don't know just yet. We do expect possibly a little bit of a price adjustment. But with us and our outstandings on our revolver, it wouldn't hurt us if we lost a little bit of borrowing base at all, really.

Makes sense. Thanks. Appreciate you squeezing me in here.

Steve Berman, Canaccord.

Just a quick, few more questions on 2016 wells. The split between Niobrara and Codell, do you feel that will be in the same 75/25 percent range as the second half of this year?

Yes. I think that's a pretty good range, Steve. When you start talking about where we're headed, that's pretty close. I think when that will start to shift is when we go into the outer core, you may see a greater number of Codells as we move out that direction in the mix. But for 2016, I would suspect that 75/25 is pretty close.

There might be some outer core wells in the mix? That was my next question. Or is that more for --

I think we'll have a few. There will be a handful in terms of what we're expecting to do. Again, we continue to move in and out of there as we see good projects come up in the outer core. We're venturing down that path somewhat. I think, obviously, our goal is to keep into the middle core as much as we can. But there are times when we shift out there just a little bit when we see good projects.

Then one more. I'm sorry if you already said this. But the timing on the three wells in the Utica, is that a second half 2016 event?

In terms of the drilling process, we're hoping that we get started on that early in the year. Then obviously that -- with the time it takes to drill, plus the completion process, we would expect that some place in the mid-year summer timeframe would be a good estimate in terms of when the productions come online.

Got it. All right, great. Thanks.

Leo Mariani, RBC Capital Markets.

Was hoping you could talk a little bit more to DJ Basin regulation and what's fallen out over there. Just any specifics you have would be helpful.

Leo, this is Bart. Yes, we've obviously, in Colorado, had a lot of, I would say, changing regulatory environment the last couple years. I think our teams have done a good job of managing all that. The current tone of things is really implementing the resolutions that came out of the Commission that the Governor set up a 1.5 years ago.

Two of those in particular, they're really related to, call it, urban development, are operators that are inside annexed areas within cities and planning drilling and completion and production operations. Those discussions are ongoing. I believe there's a goal to have those finalized by the end of the year. They're not going to severely impact PDC because most of our acreage is not in annexed areas. But we're definitely keeping our eye on a lot of this.

The second part of it is the ongoing air monitoring, air regulations, it's probably our biggest challenge right now for our operating teams. These were changes that were really implemented a little over a year ago. They continue to bring challenges as far as monitoring methane emissions and VOC emissions. We're doing a good job there also.

So yes, it's a challenging regulatory environment, but overall it's not impeding our capital programs. It's not slowing us down. But probably, this is built into the LOE number Scott talked about, it absolutely has, over the last few years, become a bigger portion of our LOE and an increasing component of our cost structure, but something that I think we're doing a good job of managing.

Got you. So, you more see the impact on the operating cost side, as opposed to the capital cost side?

Absolutely. I think that's where you're seeing most of it.

Okay. I guess just looking at the way you have described your inventory over the next couple years, it sounds like you're getting a lot of inner core wells tied-in in 2016, but then in 2017, you're talking about moving more to the outer core. I'm just trying to get a sense of when you run out of your inner core inventory?

Leo, just on that point itself, when we look at our areas of spending within the next couple years, we essentially are drilling next year -- almost all of our wells are going to be in the middle core area. There will be a few in the inner and there will be a few in the outer.

Then in 2017, we're not projecting any wells in the inner core area. Then we're projecting around 70%, 75% in the middle. Then the balance of that will be in the outer areas. But in that outer area -- yourself, as you remember from Analyst Day, there's areas in that outer core where you can get closer to the middle core and drill with higher amounts of energy and reserves closer to the middle core. So that's sort of how we see it going forward, Leo.

Okay. So, does that mean that pretty much you guys are done with the inner core drilling as you work your way into next year? Then as you work into 2017, 2018 and beyond, you're pretty drilled up there?

Yes, from where we sit today based on our current reservoir work, that's pretty well the majority of our inventory there. We'll continue to look at different opportunities in a few of the areas, but for the most part, Leo, that's correct.

Okay. Thanks.

Kris Khang, Heikkinen Energy.

Kris in for Michael Hall. A lot of mine have been answered.

A high level question I just wanted to get your sense around, you have the very strong hedge book, strong position that helps puts you in, along with the good operating results for the year. Just trying to think through how you balance growth in this environment? You could think about it as, as you are planning around the 2016, 2017 outlook, that 35% growth number, how do you think about that versus just maybe 25% and have a higher percent of your production hedged. It keeps margins higher that way --

Kris, let me take a stab at this and then I can flip it over to Lance. It's actually a really good question. Because obviously today with the changing pricing markets we sit down, we rerun our models and look at aggressive growth case, less growth.

First, you have to have a good pricing outlook. We obviously have modified our pricing outlook here in the last month based on a variety of factors. But we probably dropped our outlook by somewhere between $5 and $8 a barrel.

With that, coupled with the drilling efficiencies that Scott covered in a lot of detail, really put us in a position where we backed off and said hey, let's target a cash flow neutral next year with the somewhat frail market we're in and the strength of our balance sheet. But with the drilling efficiencies, we were still able to maintain that 35% plus growth profile. We felt extremely good about being able to be cash flow neutral and still provide that growth. Now, it's very important when you think about the growth of 2016. As Scott noted, a big chunk of that is from the five-rig pace and the 50 plus completions we're going to carry over into 2016.

Then the second part that we are looking at on this is our 2017. We want to set ourselves up to still have a decent growth profile in 2017. We don't want to drop the rig count too much to really start sacrificing that or put the Company in a shrinking position.

All of that, that I just talked about, the foundation of the entire discussion is around the slide that Scott presented, which is that our drilling projects continue to deliver returns on capital. That's the foundation of our decision. It's the only way we can continue to propel the Company growth-wise, honor the balance sheet, deliver some of the metrics we're talking about and do that in this somewhat depressed pricing market.

Lance, whatever you want to add to that.

No, I think you summarized it very well. It's all a balance of delivering strong production growth, because we have very high rate of return projects in the core Wattenberg Field. They are very strong. It goes to the bottom line then in the area that Gysle looks at because our balance sheet and debt to EBITDAX are also very strong projections for both 2016 and for 2017.

So, when we spend a lot of time sitting around working through our modeling assumptions and output, we go back and continue to kind of have a look back at a full cycle where we continue to go through and do various what-if scenarios. We really like to have that projection going forward, that balance of strong growth, strong growth in cash flow and a very strong balance sheet. All those things work together. We have a lot of optionality to be able to add a rig if the prices dictate in the future.

That's really helpful color. I appreciate it.

Then I guess a follow-up. As we look at 2015 and what you've done to date and what's anticipated for the rest of the year, there's a lot of things that you're outperforming on, working in your favor.

I'm just curious if you could rank order those, if you think about performance attributions so far this year; well performance, drilling efficiencies, increased working interest, all these things. What do you think has been the most impactful in delivering this strong performance year to date?

Let me take a stab at this. Obviously, you're asking me to rank something so this is my opinion. Scott and Lance may have a different opinion on this. But I think probably the most dramatic, I think Scott touched on this is the drilling efficiencies. For us -- PDC's not unique here. I think almost all of our peers are out talking about some of the similar trends. But to have our drilling efficiencies improve 30%. We still have some line of sight, as Scott noted on some additional efficiencies we're chasing, has been a dramatic change, a paradigm shift for us.

We changed our guidance from 119 spuds to 155 spuds. I mean, that is a significant adjustment in what we're doing. It gave us the flexibility to give consideration to dropping the fifth rig and still pursue the growth that you asked about. So the drilling side I think is the biggest improvement. Then, this is true of the market, the cost reductions. We've come down from that mid-$4 million level to the $5 million level for our extended-reach laterals to $3.1 million and $4.1 million. Our operating teams continue to push on those numbers also. So the market has adjusted in the services side dramatically.

All of that adds up at a $45, $50 oil price and $2.80 gas price that we're able to continue delivering these returns. So then you've got a lot of small pieces in here, our improving operating costs, our small technical improvements, we continue to upgrade our type curves. So we've got a lot of small things that we work on. When you add them all together, they end up being a nice contribution to the bottom line.

That's helpful. Appreciate it. Congratulations.

David Beard, Coker & Palmer.

Congratulations on the nice quarter.

Thank you, David.

Maybe just to approach the Utica/DJ question another way. As you mentioned, obviously higher oil prices dragging up NGLs, but also the NGL market itself, as well as things you're doing on the cost side. But can you envision a scenario where oil would go up, but you'd allocate capital away from the DJ to the Utica?

This is Lance. Let me give my thoughts on this.

With an increase in oil price, we have to look very closely then at our outer core area of the Wattenberg because that will really begin to impact and strengthen the economics in the outer core area. At the same time, they'll also benefit, obviously, the Utica as well. I think the key question on the Utica side is going to be, what are the NGL prices relative to oil? Secondly, what's the TETCO M2 differential?

Because those are two pieces of the value chain for Utica that continue to be a bit of a challenge for us there. But as we look at the prices going forward, we've got the flexibility to consider various capital allocations between the two fields and the specific areas within the fields to make the best decision going forward for the Company.

If I could adjust a comment there, David. I think the other part of this that hopefully everybody recognizes is, we're still very young in the Utica play. The maturity there is basically 24 wells that are producing the horizontal wells that we have out there. So when I look at it, I still see and I think our team, definitely our team sees upside to our completion process. We've seen it in the Wattenberg. We still feel like we can make headway in improving the reserves out there.

So our goal is still to get it to compete with the middle core economics. That's, as Lance described, has all these nuances to prices et cetera. But that's really where we'd like to get it. I think we can still get there. It's not going to be without some more work, though.

All right. Great. Appreciate the time. Thanks for extending the call. I appreciate it.

Thanks, Dave.

Thank you. This concludes our Q&A session. I would now like to turn the call back to Mr. Brookman for closing remarks.

Thank you, Amanda. Thank you, everyone, for the support and joining us for the second-quarter call.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program. You may all disconnect. Everyone, have a great day.