PDC Energy Inc (PDCE) 2018 Q2 法說會逐字稿

Greetings, and welcome to the PDC Energy 2018 Second Quarter Earnings Call. (Operator Instructions)

I would now like to introduce your host for today's conference, Mike Edwards, Senior Director of Investor Relations. Sir, you may begin.

Good morning, everyone, and welcome. On the call today, we have Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; Scott Meyers, Chief Operating Officer; and -- I'm sorry, Scott Reasoner, our Chief Operating Officer; and Scott Meyers, Chief Financial Officer.

Yesterday afternoon we issued our press release and posted the slide presentation that accompanies our remarks today. We also filed our 10-Q. The press release and presentation are available on the Investor Relations page of our website, which is pdce.com.

I'd like to call your attention to our forward-looking statements on Slide 2 of that presentation. We will present some non-U. S. GAAP financial numbers today, so I'd also like to call your attention to the appendix slides of that presentation, where you'll find the reconciliation of those non-U. S. GAAP financial measures.

With that, we can get started.

I'll turn the call over to Bart Brookman, our CEO.

Thank you, Mike, and hello, everyone. Let me start by thanking both operating districts in Texas and in Colorado for all their efforts in what we consider a very strong second quarter. The Delaware operations outperformed once again, helping offset difficult operating conditions in the Wattenberg field as we experienced ongoing high line pressures and some significant plant downtime in the second quarter.

We're very encouraged where we stand today heading into the third quarter, wrapping up 2018 and our outlook for 2019. Production should significantly unbundle in the Wattenberg field as midstream expansions are beginning to come online. I am happy to announce DCP's Plant 10 is up and running effective last week.

In the Delaware, our performance should continue to accelerate our growth, particularly with the 8-well Grizzly pad, our downspacing test that is beginning to come online this month. Looking forward, we expect continued financial strength. We anticipate we'll be cash flow positive for the balance of 2018, all of 2019 and 2020. Our leverage ratio is anticipated to be a 1.3 year-end '18 and our drilling projects continue to deliver stellar results.

Last, our operating efficiencies continue to improve. In Wattenberg, we have experienced a 15% improvement in our drill times, resulting in a 1 day improvement on our SRL, MRL and XRL laterals. In Wattenberg, our 2018 spud count now stands at 150 to 165 wells with the 3 rigs we have running.

Some second quarter highlights. Production of 9.4 million barrels of oil equivalent, 403,000 BOE per day. That is a 20% improvement from the same quarter of 2017. Oil production increased 25% from the same quarter last year and was 42% of our total company mix.

Production overall exceeded our expectations in the Delaware Basin and came in under expectations in Wattenberg due to the midstream constraints we experienced throughout the quarter. Overall, for the quarter, we spent $258 million, spud 49 wells, turned-in-line 53. Both are ahead of our operating plan. And as I noted, we remain extremely pleased with our per well results in both basins.

Adjusted cash flow from operations was approximately $200 million. Lifting cost $3.44 per BOE, elevated slightly due to the midstream challenges in the Wattenberg. And Scott Reasoner will cover this in a lot more detail in a moment. Our liquidity quarter-end, $680 million. Leverage ratio for the quarter improved to 1.6.

And last, our corporate netback on oil for the quarter, 94% of NYMEX, a reflection of the tremendous efforts of our marketing team, including the recent sales agreement in the Delaware, which is tied to Brent pricing and is providing tremendous uplift on our netbacks both in the Delaware and overall corporately. And Lance will give a lot more detail on this in a moment.

Next, some changes to our '18 guidance. You'll hear more about this later in the presentation, but let me hit some high points. We increased our midpoint production guidance from 40 million to 41 million barrels of oil equivalent; increased our spud count for the company by approximately 15, primarily in Wattenberg. This is a result of ongoing efficiency gains in our drilling.

Capital spend is now expected to be $950 million to $985 million, driven by increases in our spud count, increases in working interest, but also Wattenberg completion modifications, which are adding per well reserves and cost, and last, cost escalations we're experiencing in both basins.

Our oil mix for the company is expected to remain in the 42% to 45% range. We fully expect to be cash flow positive for the balance of the year. And as I noted, our exit leverage ratio should improve to 1.3 year-end 2018. Expect exit rate at the end of the year to be approximately 135,000 barrels of oil equivalent per day. Should note that's a 31% increase from the second quarter levels.

Now let me see if I can steer you through 2019. PDC should be in an excellent position for ongoing growth and capital efficiency with our balance sheet strength, quality of our drilling programs and approximately 110 DUCs starting next year. Expect our leverage ratio to approach 1.0 year-end '19, production growth for the year should be over 30% and we expect to be cash flow positive throughout '19, potentially nearing $200 million of positive cash flow. All this while we maintain a capital spend of approximately $1 billion with our current operating pace of 6 rigs total, 3 in each basin.

So let me wrap up my comments by saying we are extremely excited about where PDC stands today. Our Delaware has tremendous momentum right now. Our Wattenberg is positioned to demonstrate substantial production growth over the next couple of years, particularly with the startup of the long awaited third-party midstream expansions. This growth, along with our balance sheet strength and the quality of our inventory, positions the company for ongoing success for many years.

With that, I will turn this call over to Scott Reasoner for an update on our operations.

Thanks, Bart, and good morning, everyone. Before I jump into the operational updates from the quarter, I want to quickly take a minute to also express my gratitude to our teams.

For the past year, our Wattenberg team has done a great job handling in incredibly tough operating conditions in the field in a safe and effective manner. The midstream constraints were challenging all the way through our organization, from our asset planners to our corporate strategy team. And with the recent startup of DCP's Plant 10, we are extremely excited for what the second half of the year could deliver.

As you can see on Slide 7, the second quarter marked the first time that PDC has averaged over 100,000 barrels of oil equivalent per day, a great milestone. Year-over-year, oil production growth of 25% continues to outpace total production growth, a testament to the continued execution of our Delaware Basin teams and the tremendous productivity we're seeing in the field. Delaware production grew approximately 20% over the first quarter to nearly 25,000 barrels of oil equivalent per day, or almost 25% of total PDC production.

Slide 8 gives a look at our updated capital expenditures for the remainder of the year. You can see that for the second quarter our capital investment was approximately $260 million. For the full year, we now expect to spend between $950 million and $985 million, an increase from our prior estimates of $850 million to $920 million.

This increased investment is due to several factors. The first piece of this increase is largely a result of our recent Wattenberg acreage trades. Through these transactions, we acquired added working interest in a number of our operated wells that has added approximately $35 million of CapEx this year.

Second is drilling efficiencies. As Bart alluded to, we continue to make strides in our Wattenberg drill times. We now project our spud-to-spud drill times to be 5, 7 and 9 days for an SRL, MRL and XRL. This represents an improvement of 1 day per well or approximately 15% and results in our expected spud count for the full year to increase to a range of 150 to 165 wells, as shown on the right hand side of the slide. The incremental investment associated with additional spuds is approximately $25 million for the full year.

Next, we modified the timing of the upgrades in our Central Delaware gas gathering system. That is a result of well over performance. This equates to approximately $15 million of incremental Delaware midstream investment.

The last factor leading to an increase in our capital budget is the impact of increased well cost in both basins. We give more detail on the moving parts on the right hand side of the slide, but generally speaking, we're seeing 5% to 10% increases in our service cost, net of efficiencies gained by our operating teams. The added frac stages in the Wattenberg will be discussed in detail in a moment.

The fifth and final factor in our CapEx re-guide is the reduction to our estimated full year spend in leasing, seismic and non-operated wells. These reductions add up to approximately $55 million, resulting in our updated range of $950 million to $985 million.

Before moving on, I want to stress that while there are a number of moving parts in our new guidance, the lion's share is associated with projects and efficiencies that are expected to lead to increases in production, reserves and cash flows.

Moving to Slide 9. We give a snapshot of our quarterly production LOE trends. On the production side, we clearly message that continued outperformance from our Delaware asset in the second quarter has essentially offset the tough conditions faced in the Wattenberg, especially in the latter half of the quarter.

Fortunately, with the recent startup of DCP's Plant 10, we anticipate a much stronger production profile out of the Wattenberg for the remainder of the year. This should help our corporate production increase from just over 100,000 barrels of oil equivalent per day in the second quarter to approximately 135,000 barrels of oil equivalent per day average in December.

On the LOE side of things, high line pressures and multiple instances of plant downtime in the Wattenberg led to higher cost than anticipated. Combined with the impact to production I just described, our LOE per BOE was really double hit. However, we're excited about our Delaware lifting cost for the quarter coming in at less than $4 per BOE. This is a direct reflection of both our infrastructure investments and the production outperformance.

For the full year, we now expect corporate LOE per BOE to be between $3 and $3.15 per BOE, a modest increase from the previous range, much of which is associated with the midstream related challenges of the Wattenberg through the first half of the year.

Switching gears, Slide 10 gives more color to our Wattenberg completion enhancements. In a traditional well, the surface location and lateral toe are approximately 500 feet from the edge of the lease line in order to maximize PDC's interests. Now that we are largely our own offset operator, the first change to our development plan was to drill the toe a bit closer to the line, as shown on the diagram. This leads to an additional 2 stages per well on average.

Next, our team modified the heel. In prior cases, completions began when the lateral hit 90 degrees. Now we begin completions at 60 degrees, picking up an incremental 3 stages on average and roughly 650 feet of additional lateral.

These changes do not have a direct reflect to our inventory, but on a 10 well pad of XRLs, we expect to essentially complete one additional well, accessing approximately 10% additional rock compared to our prior method. These are incremental reserves with full completion costs, but only small incremental drilling costs that will drive up our overall well returns. This is a great example of the continuous tweaks and modifications our teams continued to deliver and should be a nice incremental boost to production, reserves and returns.

Moving to the Delaware. We continued to see strong sequential growth quarter-over-quarter, driven by outperformance and execution. We expect this trend to continue through the back half of the year as our 8-well Grizzly pad finishes completions.

As you can see on the left hand side of the slide, our Wolfcamp B and Wolfcamp C wells are already online, with early production results just starting to come in. Look for the 6 Wolfcamp A wells to come online later this month, with a handful of additional completions through year-end. Just to remind everyone, this is our 12 Wolfcamp 8 wells per section equivalent downspacing test.

In Block 4, we continued to see really strong results, with second quarter turn-in-lines in the area averaging approximately 290 barrels of oil equivalent per day per 1,000 feet and a 60% plus crude.

The graph on the left side of the slide shows that the average production from our -- shows the average production from our Wolfcamp A and B wells. I want to emphasize, these are normalized to an MRL equivalent length.

You can see that our Wolfcamp A wells have been a bit stronger overall, but both zones are delivering really strong results in the A and B, tracking 2.25 and 1.25 million barrels of oil equivalent EUR curves respectively. I want to stress that these results are still very early with a limited well count, making the EUR a rough estimate at this point.

Last quarter, I outlined our water management system in Block 4. On Slide 13, you can see the oil gathering system and oil treatment facilities we're currently investing in, with portions of the system shown on the map to be installed in the second half of 2018.

With a design for future volumes, we expect to see safety and cost benefits of this investment as it is projected to lead to reduced pad facilities, reduced potential air emissions and reduced reliance on trucking as well as increased oil price to our wells. As it stands, our most recent 10 wells in Block 4 are currently tied directly to pipe and by year-end we expect approximately 90% of our Block 4 crude volumes to be on pipe. Tremendous work from our major projects and infrastructure team thus far.

Finally, on Slide 14, we highlight our North Central acreage and recent well results. Year-to-date, we've turned-in-line 7 wells in the area, with average peak 30 day production of approximately 220 barrels of oil equivalent per day per 1,000 feet and over 50% crude. Both of these figures are above our original expectations, and as you can see on the graph, tracking a type curve of approximately 2 million barrels of oil equivalent. The same point here as in our Block 4 area, the EURs are from early production and limited wells.

We're currently in the process of upgrading some of our facilities in the area in order to handle some of the outperformance we've been seeing. Look for us to remain active in this key focus area moving forward.

I'll now turn it over to Scott Meyers for a financial update. Scott?

Thanks, Scott. I plan to focus primarily on the results of the quarter, which were largely in line with our expectations, before giving an overview of our updated financial guidance.

Several positives to takeaway in terms of U.S. GAAP measures, including year-over-year increases in production, total sales and net cash from operating activities. Of note, production growth of 17% compared to the second quarter of 2017 is slightly different than the 20% referenced by Bart and Scott due to the inclusion of our Utica production in the prior years of approximately 2,400 BOE per day.

Net loss for the quarter was $160 million compared to net income of $41 million in 2017. There are 2 main non-cash drivers in the difference between the periods. First, despite the 50% increase in total sales, our total revenue decreased year-over-year due to a $150 million loss in commodity price risk management in the second quarter of '18 compared to nearly $60 million gain in 2017. The majority of these figures are the mark-to-market adjustments due to the changes in strip pricing during the respective quarters.

Second, due to the Delaware Basin gas differentials and the upcoming lease expirations, we impaired $160 million of non-focus area acreage this quarter. The acreage had significantly higher GOR compared to our focus area and thus makes economics very challenging in the current environment. The location of the impairment includes the remaining Western area acreage and the acreage in our South-Central, primarily located in and around the Grisham fault.

Most importantly, we feel that due to the successful drilling of our focused areas, these locations would not have been developed before the lease expirations. We still maintain our estimate of approximately 450 MRL equivalent locations in our 2 focus areas. Finally, the strength of the quarter is truly seen in our 30% growth in cash flow from operations.

Quickly touching on non-U. S. GAAP measures, please note that the reconciliations can be found in the appendix at the end of the slide deck. Both adjusted EBITDAX and adjusted cash flow from operations increased compared to the second quarter of 2017, largely driven by the aforementioned increase in sales.

I'll note too, nonrecurring items are included in the numbers shown. In our 2018 adjusted net income, the aforementioned impairment and tax impact are included. Excluding these figures would have resulted in an adjusted net income of nearly $37 million for the quarter.

Second, our adjusted EBITDAX in the second quarter of 2017 includes approximately $40 million of proceeds related to the old MK note. Excluding these proceeds would have result in a year-over-year increase in our adjusted EBITDAX of approximately 35%.

And again, you can see the steady quarterly growth of adjusted cash flow from operations over the past 5 quarters, which results in almost $200 million in the second quarter of 2018.

Moving on to Slide 18, we give an overview of our production cost both in terms of absolute dollars and dollars per BOE. The first thing you'll notice on the slide is our quarterly LOE of $3.44 per BOE compared to $2.50 in 2017. As Scott described earlier, the double impact of high line pressures and plant downtime in the Wattenberg impacted both our cost and production in a negative way.

The second factor impacting our overall corporate LOE is the increased percentage of total production that the Delaware Basin now accounts for. In our original budget, we anticipated Delaware to account for between 15% and 20% of total production at this point. As Scott mentioned earlier, the actual number is more in line with 25%. As the Delaware is an inherently more expensive operating basin than the Wattenberg, this relevant increase increases our overall LOE per BOE. We are however very proud again to say that we came in below $4 per BOE in the Delaware Basin for the quarter.

Before moving on, I'll reiterate what I mentioned on the first quarter call. As the Delaware becomes a larger and larger piece of the company's overall story, we'll be very satisfied to have a corporate LOE in the neighborhood of $3 per BOE. Expect us to get back to that level as the Wattenberg production unbundles through the remainder of the year.

As of June 30, we have a leverage ratio of 1.6x and liquidity of $680 million. Entering the second half of the year, we have updated our commodity price forecast to reflect the increased strip price environment and widening oil and gas differentials that we are exposed to.

When adding the increased well cost that Scott explained and the overall higher capital budget, offset by the increased production, we expect our 2018 outspend to be between $75 million and $100 million. Most importantly, we project to deliver free cash flow in the second half of '18 and exit the year with an undrawn revolver.

Finishing up on Slide 20, we'll show our updated 2018 financial guidance. We've already touched on production, capital investment and LOE per BOE, so I'll spend a quick second on a few other metrics.

First, our price realizations remained unchanged. As it stands, we're probably tracking towards the upper end of the range for oil and NGLs and at the lower end of the range for natural gas. We also remain confident in the projected commodity mix for the year, including our 42% to 45% crude oil.

You'll notice our TGP range increased about $0.20 to $0.80 to $0.90 per BOE. That is a direct result of delivering more volume on pipe than originally expected. We're obviously very happy with the environmental and safety impact of this trend, while our overall financial statements are unimpacted as the difference in the cost is absorbed in our realizations.

Without giving too much away from what Lance is about to present, the cost assumptions and commodity mix and the pricing shown here are by and large reflected in Lance's long-term outlook.

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

Thanks, Scott. Let's now look at Slide 22. Our company is on the verge of a substantial unbundling of our production volumes in Wattenberg. On August 1, DCP Midstream announced the startup of Plant 10, a 200 million a day gas plant with associated compression in the Wattenberg field that we expect will bring strong production growth to the company in the second half of 2018.

With Plant 10, DCP's system capacity in the DJ Basin increases to over 1 Bcf a day and we fully anticipate that we will maintain our share of their system capacity based on historical usage and drilling activity. Typical with the startup of new facilities like Plant 10, we expect to experience reduced line pressures, which in turn results in increased production volumes from our wells, from our older vertical wells to our most recently completed horizontal wells.

Included in DCP's recent announcement is their multiyear fully integrated midstream infrastructure growth strategy. This long-term strategy looks out over multiple future years to ensure DCP's midstream capacity and product takeaway capabilities, expand to accommodate the growth in producer's volumes over the time.

Next, in DCP's growth plan is Plant 11 that has a projected in-service date in the second quarter of 2019. This plant and associated bypass brings an incremental 300 million a day capacity on DCP's system. Then Plant 12 is expected to begin initial phases of operations in 2020, with a potential for up to 1 Bcf a day of incremental capacity, including bypass over time.

In addition to our volumes on DCP system, we also have about 25% of our 2018 projected volumes on AKA Energy's system. AKA is also in expansion mode, with a recently completed plant that's projected to increase their processing capacity to approximately 40 million cubic feet per day. This does not include incremental PDC volumes going to AKA that are then offloaded to the West Anadarko midstream system infrastructure.

The last point on this slide shows additional infrastructure expansions currently planned or underway that will facilitate overall production growth in the basin. We're very thankful to have secured significant flow assurance at competitive pricing in the Delaware Basin. Last quarter, we announced a significant Gulf Coast-based crude oil sales agreement that provides firm physical takeaway capacity and international pricing exposure. This 5.5 year agreement which began in June is projected to result in competitive netback crude oil prices relative to Midland throughout the entire 5.5 year term. The near-term impact of this agreement is significant to our Delaware oil netback pricing.

For the 1.5 year timeframe from July '18 to year-end '19, the sales agreement is projected to cover approximately 85% of our estimated volumes, with the balance being sold into the Midland market. Also, over the 1.5 year timeframe, the company projects an all-in oil netback realization range of 88% to 92% of NYMEX crude oil pricing, which also includes an estimated 15% of our bonds being sold into the Midland market that is currently experiencing a significant differential over that time period.

We're only 2 months into the contract, but for the month of June we realized an all-in netback of about 92% of NYMEX for our entire Delaware oil volumes, which is at the high-end of our range.

Now to our gas market initiatives. Given our projected growth profile and focusing our efforts on flow assurance given the near-term tightening of gas takeaway out of the basin, we recently announced that we had secured additional gas sales agreements in our Eastern and South-Central areas.

We currently have firm transportation contracts that ramp to approximately 75 million btu per day to physically deliver to Waha. Then in Waha, we have firm sales agreements based upon Gulf Coast pricing over the next 18 months.

We expect the 3 new build gas pipelines planned by the industry out of the basin will bring much needed capacity beginning in the fourth quarter of 2019. We will continue to monitor forecast of gas lines and expect to lay an additional firm agreements as production ramps from the basin.

For our North-Central area, PDC's gas volumes are sold at the wellhead to ETC and marketed via their downstream infrastructure. We are very pleased with our sales agreements and believe that they achieve our 2 key marketing objectives: to ensure takeaway capacity for our future development plans and to realize competitive netback pricing both in the short-term and the long-term based upon the current market forecast. I want to again thank our marketing and midstream teams for the proactive approach to seeking out long-term sales agreements that assure both takeaway capacity and competitive netback pricing.

Last year at our Analyst Day, we highlighted that we would continue to build out our Delaware Basin midstream asset positions, and with that, we would potentially consider various midstream asset monetization strategies in the future.

The purpose of this slide is to provide an update that we have launched a formal process to evaluate the potential strategic midstream transaction and have retained Jefferies as our financial advisor. The assets included in the potential monetization include oil and gas gathering, gas compression, water gathering and disposal wells and future gas processing rights.

Some of the specific company owned and operated facilities we expect to have in place by year-end '18 include oil gathering and treating systems in Block 4, gas and water gathering lines, SWD wells and a water management system.

And as we've previously highlighted, the potential monetization structures include either a full or partial monetization, a joint venture, or we may retain 100% ownership. The process is well underway, and while hard to predict timing, we anticipate we'll have a plan of action in the fourth quarter of this year.

Now Slide 25. In this final slide of our second quarter earnings call, we wanted to provide an updated outlook, which now includes 2020. This scenario assumes that we maintain our current 6 rig corporate pace in all years. I want to highlight upfront that this model is based on several input assumptions based on where we sit today, and that our official 2019 budget has not yet been completed.

First of all, let's look at a couple of the key outputs. The 3-year production CAGR is projected at nearly 30%, with a 2020 exit rate of approximately 200,000 BOE per day or nearly double our second quarter 2018 volumes. As you may recall, this is the same projected 2020 exit rate we provided at our Analyst Day in April of 2017, but now with a couple of significant updates, that demonstrates our increased capital efficiencies.

Today's 2020 outlook scenario utilizes 6 total rigs in all years, which is simply a steady state continuation of what we're doing today. That compares to our 2017 projection that ramped to 12 rigs by year-end 2020.

To show that impact in capital dollars, today's 2020 outlook projects a cumulative capital program between 2018 and 2020 that is more than $500 million lower than our last year's Analyst Day projection over the same 3-year period.

This is a tribute to all our teams and their focus on innovation as they continue to deliver increased capital efficiencies on several fronts, including increased lateral links, consolidating leasehold trades, efficient completion designs and improved drill times.

There are 3 additional input assumptions I would like to highlight on the slide. First, we've increased our drilling completion cost based upon estimates that include the service cost pressures and the efficiencies that we've highlighted today. Second, we've updated our model to include the impact of current widen differentials. And then finally, our outlook NYMEX oil prices assume $65 per barrel in 2019 and $60 per barrel in 2020. Even with these adjustments, this 6 rig scenario projects to build more than $400 million in free cash flow from the second half of '18 through 2020.

Looking at the table in the lower right, this 6 rig case then projects a yearly leverage ratio of 1.0x times in 2019 and 0.8x in 2020. Keep in mind this metric does not include the projected $400 million in free cash on hand. Based on the forecast of production, we project cash flow of about $1.35 billion at the midpoint in 2020, again at $60 per barrel oil.

One of the new metrics we're beginning to track is cash flow yield. For 2020, we project that this 6 rig corporate case delivers a range of 10% to 20% and then in 2020 a range 20% to 25%.

One of the final items to highlight are potential considerations for 2020. In this section of the slide, we're highlighting several key factors and options that the company plans to evaluate as we get closer to 2020. It demonstrates the flexibility and optionality we have in our portfolio to adjust to market conditions, including the potential to add a fourth rig in Delaware or to accelerate additional Wattenberg completions.

So to summarize, our updated 2020 outlook, utilizing the scenario of 6 corporate rigs, is projected to provide strong growth in production, cash flow and free cash flow through 2020. This outlook demonstrates our improved capital efficiencies, our ongoing focus on increasing long-term shareholder value. This growth is driven by our organization and we're very thankful to have such a strong team at PDC.

Now before we turn it over to the operator for Q&A, I want to hand it back to Bart to quickly discuss the Colorado political front.

Thanks, Lance. Let me finish by addressing the recent submittal of signatures around statutory Ballot Initiative 97, which is the proposed 2,500 foot setback. As you are aware, proponents for this setback claim to have collected 171,000 signatures. And 98,492 valid signatures are required for it to be on the ballot in November. And the secretary of state has until September 5 to complete this validation process.

If there are enough signatures, we being, PDC, along with the greater business community are prepared to defeat this initiative. We are committed to ensuring voters in Colorado are aware of the extremely negative consequences to our industry and the economy in the state of Colorado if this initiative passes. Bottom line, as an industry we are confident we can defeat this ballot initiative.

Justin, that's all we have here, so we'll turn this back to you for Q&A.

(Operator Instructions) Our first question comes from Welles Fitzpatrick from SunTrust.

Bart, I appreciate the comments on 97. Especially, I was going back yesterday and looking at your comments on the 2Q '16 call about -- I think it was 9 -- or 75 and 78 then. And you were right about the number of signatures a couple years back. Just to be clear though. Even if 97 passes, does it have any impact on existing permits or DUCs?

I don't know if I have that answer, Welles.

I believe -- Welles, this is Scott. I believe the way that's written and everything that we've taken a look at, it would allow us to continue to drill with the permits that we have and complete the DUCs that we have.

And then any comments on the Farm Bureau's 108 measure?

Signatures have been submitted and that was well over 200,000. We have a lot of confidence. Research shows right now that the voters view this as a very favorable initiative. So we have a lot of confidence that the Farm Bureau is moving forward with this and it will be well received by the voters.

Can you share a favorability rating or any quantification?

Not in a position to share any of that.

Totally understood. If I could sneak one more in. With the heel completion at 60 degrees, just for my own clarification, you can do that in all zones, is that a correct interpretation?

Yes. Well, I think that we really look at that and say it's within the Niobrara section. And generally it's in the section that we are targeting. But it may move toward the top end of it obviously as we move up that angle a little bit farther. But yes, it's something that's really -- has obviously no drilling cost. But we have to have the stage cost as part of that and definitely is a very efficient and economic process.

Our next question comes from Asit Sen from Bank of America.

Lance, in the 2020 scenario, could you talk about anticipated completion split between Delaware and Wattenberg? And then I was wondering on the 135 MBoed exit rate this year, what should we expect as the Delaware exit rate? And then could you kind of talk about broadly thoughts on 2019 Delaware exit rate?

Yes, sure. So let me start just a little bit on the TILs that we're projecting for 2020, was the first part of your question, with that, Asit. And these are approximately, say, 175 wells that will be in the Wattenberg and approximately 35 to 40 that's in the Delaware. So that's sort of the breakout between the turn-in-lines for 2020 at that point in time.

As far as the breakout of exit rate, the 135,000 barrels a day...

It's roughly 100 to the Wattenberg and the remainder to the Delaware. That's pretty close.

And then as far as 2019, I don't know if we have published an exit rate. The only thing we've given is we have confidence we can grow corporate production annually by over 30%.

And then on managing cost in the Delaware, could you talk about the use of local sand and progress on water recycling? And then how does the monetization of the midstream assets affect LOE or how should we think about it?

This is Scott and I'll answer the first part of your question and then Lance I think will jump in on the monetization process. When you look at the sand down there that we're getting, obviously it's in a place where we're still using a split between 100 mesh and 40/70. It's roughly a 50-50 split. The 40/70 I believe is still coming from the north. We're not acquiring that in the basin. The 100 mesh -- where we can get it and when we can get it, we are using the local sand. We have not seen any reduction in the capacity of the wells to produce and there's an obvious cost savings that we're excited about using there. So as far as the availability, we are getting quite a bit of it, but it's not 100% at this point. When you talk about water recycling, we have a tremendous amount of work by our infrastructure team. They put in water recycling capacity, the storage, et cetera. And on our Grizzly pad, that's where we executed and we ended up in that range of 30%, 40% with some early issues around getting clean enough water, getting it processed enough as we produced it to use it in those frac jobs. So that's why that percentage was pushed down a little bit. But really looking in that 30% is what we've done. Our hope longer term, as we've discussed before, is to continue to increase that, but we want to do that without obviously impacting the quality of the wells that we are generating.

And to answer your question with the potential monetization of the Delaware infrastructure, obviously the different structures would impact how the numbers are affected. But if you were to assume 100% outright sale of everything, you would have some increases to your TGMP or transportation costs and you'd have some increases to our LOE costs. But you'd have reduction to our capital cost. Because basically what is happening in our financial statements today is we have CapEx, capital costs that are in the numbers which helps reduce some of your operating expenses.

I appreciate the color. And Bart, thanks for the update on Initiative 97. Just for investors, could you kind of highlight some of the important dates to look out for?

Okay. I think that we've got -- over the next week to 2 weeks you're going to see a -- let's call it a gross signature count. And I can't give you an exact on that. We have September -- if that is sufficient to justify a validation process, the secretary of state has till September 5 to determine if there are a number of valid signatures. If that happens and it is on the ballot, you have September 5 to November 6, which is election day. I can promise you there will be a very intense campaign by the industry and the pro-business people in Colorado if it ends up being on the ballot. So those are probably the 3 big. The next couple of weeks as far as getting a gross count, a validation process through the secretary of state. And then if it were to make the ballot, November 6.

Our next question comes from Irene Haas from Imperial Capital.

(technical difficulty)

transportation to Gulf Coast area. My question for you really has to do with your hedging strategy for specifically oil and gas in 2019.

Irene, can you repeat the question? You got cut off on the front end there.

Okay. Hedging strategy for 2019 in both oil and gas to complement your sort of long-term transportation arrangements?

Thanks for the question, Irene. When we look at our hedging strategy, our number one thing is we want to make sure we can protect our cash flow from a downturn to give the market time to adjust as well as our operating teams. So where we're sitting at for right now with the debt and leverage ratio we have, we feel pretty comfortable with what we've hedged so far for 2019. That doesn't mean that if there's some opportunistic opportunities we couldn't do a little bit more. But when we really look at our figures, we could have a $40 oil price and with some of the operational changes we would have, we could still have a positive cash flow and debt-to-EBITDAX that's less than 2x. So those are some of the key numbers that we'd used to help guide us. It's not as much of a balance between how much oil and gas. It's really about the value and the cash flow that the output of those commodities have and what's the right and appropriate way to protect the company.

Our next question comes from Jeoffrey Lambujon from Tudor, Pickering, Holt.

Was just hoping to dig in a bit more completions and I guess the DUC plan, but in the 2019 timeframe. Looking at the accelerated spuds between now and just thanks to efficiencies and the benefit really starting to show up as you move into 2020. Can you just kind of bridge the gap there in terms of completion crews and your thoughts on that through 2019, what the DUC profile looks like just as we look at '19 and '20?

Sure. So for 2019 our current outlook is projected to have 3 rigs in each basin and one frac crew in each basin. And so that's our current base plan there. From a DUC standpoint, as Bart talked about earlier, we're actually in 2018 with around 110 DUCs with the company. That actually grows in 2019 to probably the 140 DUC range with both basins. And then leaving out of year 2020, Jeoff, we're probably back down to around 130 DUCs. So we're talking through 2020 here with our outlook, but keep in mind, again, we're taking 130 DUCs out of 2020 on into 2021. So it positions the company very well from a continued growth standpoint with that.

And then just one more of a clarification question still on the multiyear base case. Just looking at how we go from $65 oil to $60 in 2020, just want to make sure I understand how inflation or the inflation assumption changes if at all across that timeframe? Are you keeping it flat? Or does that parry back a bit as you come down with commodity prices?

Jeoff, we're actually keeping it flat to what we're projecting for well cost today. Today's cost is around that $65 per barrel that we're seeing for WTI and so the prices we have for drill cost are sort of based on $65. And so we kind of keep that the same then for 2019. And then when you see 2020 dropping to $60, I think we feel pretty good that keeping that flat is probably the right thing to do in that year.

Our next question comes from Paul Grigel from Macquarie.

Maybe one for Scott Meyers here regarding the impairment. What could be the future risk for additional impartments, especially if natural gas prices weaken further in the basin?

Yes. When you look at it, our core focus areas are our oilier properties, so the impact of natural gas prices on those locations really is not significant. So from my standpoint where I am sitting are 450 MRL equivalent locations, which is in the North-Central and the Block 4 area. The gas does not have nearly as a significant effect as oil would, so I don't anticipate anything significant in those areas.

And then I guess related to that, what's the potential organic upside that could exist to the 450 location count that you mentioned in the Delaware as you guys move forward?

This is Scott, and I think Lance probably has some comments on this too. We're doing a significant amount of testing right now and I'll speak particularly to our Grizzly Pad. We're at 12 wells per section equivalent on that 6 well test that we're doing, gives us some upside to accounts. We have Bs and Cs that we're working on as well and we're considering other zones within the overall project. So we really have a -- we have a lot of upside I think in the Delaware. And there's parts of that acreage that we're still testing even in and around there in the various zones.

And Paul, I do believe -- this is Bart -- I do believe we have a bone spring test…

We do schedule for the fall.

Scheduled for the fall, which we're excited about. And I believe we have some non-operated interest in some bone spring tests. So we're just starting to get some trickle data in on that, which again we're excited. So I think we've got some confidence that over time -- and this is probably going to vary as you go from the Central over to the Eastern block -- that we're going to find additional opportunities either through downspacing in other zones across the core oily acreage blocks.

And then kind of [benefit] from the offset operators, as Bart was describing, not only in the wells we participate in, but as they release data. That will help us understand the additional rock out there.

My only advice on this question is please be patient, and this is PDC and all operators, because the time it takes to drill these pads and test these zones, and most important, to under the production profile and the reserve profile of these wells, some of these tests could take a year to 2 years by the time we have conclusions. So I just want to put that out there because that's the reality of this basin.

And then I guess just one last quick one. Do you guys have any thoughts on potential initial uses for the free cash flow that's projected to be generated starting in the back half of the year here obviously through the 2020 projected period?

Yes, in the -- well, obviously, we've had this forecast up for a while and we've had this question a lot. And I think to start, obviously strengthen the balance sheet as a starting point. We're constantly in the market. Lance's team are looking for opportunities to build on what I would call quality inventory gains, while we have a strategic focus on maintaining long-term quality inventories in both basins. So I think that would be a high priority. We would give consideration, always honoring our balance sheet to expanding our capital spend slightly. And that could be through some acceleration of those DUCs we were talking about or potentially reviewing again. We're not planning on that rigs right now, but we would give that consideration of maybe adding some rigs midyear or rig midyear. So I think those would be our first 2. And then obviously you have the stock buyback, which seems to be the current trend in the market for a lot of different industries and also in the E&P sector. That's probably a lower priority for us. And then the last would be dividends. Paul, we're -- and we get that question a lot. Probably a low priority for us right now, not absolutely off the table, but I think we have to be careful about the size of the company and where we're at, even jumping into that arena yet. So hopefully I answered your question.

(Operator Instructions) Our next question comes from Dan McSpirit from BMO Capital Markets.

Bart, beyond an issue of 97, what does the changing political landscape in Colorado mean for growing the company? That is, are you more inclined to put your next acquisition dollar to work outside of Colorado given the political overhang that just won't quit? Or do you see a deep value opportunity emerging here in the DJ Basin?

Dan, I think -- no, I don't think we have right now -- I think Lance continues to look at good value add opportunities in both basins. We recognize we've got an ongoing battle here. We have a lot of confidence. We're going to continue to educate our voters. I think we recognize we have this opposition and these are the fights that we have to expect to continue. But I have a lot of confidence where we're at right now and how we can get through some of these challenges. So I don't think we necessarily have a shifting strategy to say "less Colorado, more Delaware." I think if there's anything, there will be some consideration on how we develop these assets and the pace. Right now we've got our 3 rig and our 3 rig and we're happy with that. So -- but I think it's a fair question. And there's nobody whether you are in the oil and gas business or any other businesses in Colorado right now -- we recognize we have a shifting demographics and this is one of the things we have to work with. And I have a lot of confidence in our community relations, government relations teams, our relationships over at the state and how we're managing this. So -- it doesn't take away the disappointment of this last week in our equity performance and these signatures being submitted, but I think this is just a message of the things we had as our opposition and we've got to be prepared to fight it.

And as a follow-up, Lance, could you discuss further how DCP Plant 10 will work? You mentioned maintaining market share based on historical production, but what is the risk if the company's productive capacity is limited and production comes up short of what's expected? Just trying to get a handle on the risk here.

Yes. So we've done a lot of modeling on this, Dan, and we feel confident in our ability to maintain our allocations within the field through DCP. We currently have a range of, say, 25% to 30% of DCP's total throughput. And we've done a lot of modeling. We understand the hydraulics. We've been thoughtful around understanding where compression is going in within the system. And we've been very active drilling. So we put all those things together and we feel very solid in our abilities to deliver on the volumes that we've provided and projected as part of our guidance range for 2018.

And if could add to that, Lance, just quickly. I do want to say that where our properties are located are very much central to the overall DCP system and I think that does give us an advantage in terms of making sure we get to produce what we can produce. And I think we are at a place where the system that they are installing is definitely beneficial to us, as Lance was describing.

Our next question comes from Kyle Bickel with Stifel.

Just one quick follow-up on something you guys touched on earlier. With the new completion design in Wattenberg -- I see the example that is on the XRL -- I guess one, is that exclusive to the XRLs or do you see that working on both standard and mid reach? And then also, is this something you anticipate you might be able to transfer down to the Delaware?

In terms of the lateral length, it affects all of them. So we're doing this completion method on the XRLs, MRLs and SRLs. It actually adds percentage greater to the shorter laterals obviously. As you shorten that lateral, that additional footage on those laterals is a greater percent than just 10%. So that's a real benefit. And I appreciate that question, because if that's not clear, that's something we need people to understand. When you talk about transferring it down to Texas, the rules are different down there and we have to make sure we use the distances that are appropriate for the position that we are in down there. As far as whether we can transfer this, I would have to dig into that farther before I could even comment on it I guess, Kyle. I am sure we're taking a look at it, but it's something that's -- again, the rules are down there. And I believe we are already pushing the limits that we can push in most circumstances.

Thank you. I am showing no further questions. I would now like to turn the call back over to CEO Barton Brookman for any further remarks.

Thank you, Justin, and to say thank you to everyone listening in today. We really appreciate your ongoing support of PDC as a company. We're extremely excited about our outlook as we describe not only the balance of this year, but where we're headed the next several years. So more to come. And again, thank you for joining the call.

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