May 3, 2018
Executives
Michael G. Edwards - PDC Energy, Inc.
Barton R. Brookman - PDC Energy, Inc.
R. Scott Meyers - PDC Energy, Inc.
Scott J. Reasoner - PDC Energy, Inc.
Lance A. Lauck - PDC Energy, Inc.
Analysts
Asit Sen - Bank of America Merrill Lynch John Nelson - Goldman Sachs & Co. LLC Welles Fitzpatrick - SunTrust Robinson Humphrey, Inc.
Park Carrere - Scotia Capital (USA), Inc. Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
Brian Corales - Johnson Rice & Co. LLC Oliver Huang - Tudor, Pickering, Holt & Co.
LLC Paul Grigel - Macquarie Capital (USA), Inc. Kevin Moreland MacCurdy - Heikkinen Energy Advisors LLC Michael McAllister - MUFG Securities America, Inc.
Operator
Good day, ladies and gentlemen, and welcome to the PDC Energy First Quarter 2018 Conference Call. At this time, all participants are in a listen-only mode.
Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, today's conference is being recorded.
I would now like to introduce your host for today's conference call, Mr. Mike Edwards, Senior Director, Investor Relations.
You may begin, sir.
Michael G. Edwards - PDC Energy, Inc.
Good morning, everyone, and welcome. On the call today we have Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; Scott Reasoner, Chief Operating Officer; and Scott Meyers, Chief Financial Officer.
Yesterday afternoon we issued our press release and posted a 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 a reconciliation of those non-U.S.
GAAP financial measures. With that, we can get started and I'll turn the call over to Bart Brookman, our CEO.
Barton R. Brookman - PDC Energy, Inc.
Thank you, Mike, and hello, everyone. First quarter of 2018, a strong quarter with solid results slightly ahead of our expectations.
And where we stand today, a couple of significant catalysts should accelerate our growth and financial strength as we progress through the second half of 2018 and into 2019. Let me quickly cover those.
First, DCP's start-up of Plant 10 expected late this summer should significantly unbundle our Wattenberg production and is the first step in a series of major midstream expansions over the next couple years that should provide long-term capacity for our production. Second, our ongoing Delaware results.
Production is exceeding our expectations both basin-wide and individual well performance. These impressive results should gain even more momentum through the end of the year as we continue to streamline our drilling, completion, production, and midstream operations.
Some first quarter highlights. When compared to first quarter 2017, a 34% improvement in production to 8.9 million barrels of oil equivalent or 99,000 Boe per day.
And very important, our oil production improved over 50% from the same quarter last year. This production exceeds our internal expectations.
And given the challenging midstream situation in Wattenberg, we were very pleased our corporate production was 5% above fourth quarter 2017 levels. The oil mix for the company remains strong at 43% primarily due to the growth in the Delaware Basin.
And in the Delaware, we turned in line seven wells, the majority of these in our Central area, and all wells are meeting or exceeding our early production expectations. Overall, we are extremely pleased with the Delaware team's execution as we gain traction in almost every phase of our operations.
Now let me hit some key financial metrics for the quarter. EBITDAX improved nearly 50% from the same quarter last year primarily due to improved production and commodity prices.
Lifting cost, $3.33 per Boe. This is up slightly primarily due to some one-time events in Wattenberg, and Scott Reasoner will cover this in a lot more detail in a moment.
But overall for the company, we are on target for our annual guidance of $2.75 to $3 per Boe lifting cost. Liquidity quarter end, $745 million.
And a strengthened balance sheet; leverage ratio improved to 1.7 times. Capital spend, $250 million.
This is right in line with our internal expectations. Overall, we are extremely pleased with the financial condition of the company and look forward to the second half of 2018 when we anticipate we will be cash flow-positive.
Next, what to expect for the balance of 2018 and leading into 2019. Production should dramatically improve as we go through the second half of the year.
We should exit 2018 at approximately 130,000 Boe per day. Our DUC inventory will build slightly as we close 2018 given a strong operational momentum as we head into next year.
And we anticipate we will be cash flow-positive full year 2019 while we continue to strengthen our balance sheet; all this while we maintain our operational pace of three rigs in both the Wattenberg and Delaware Basin. Steady state operations, cash flow-positive, strengthening balance sheet, and strong production growth; a very positive story.
Now let's talk longer-term for the company. Later in the presentation Lance will give an update on two items we believe are key to our success, both in the near-term and over the next 5 to 10 years.
First, the quality of our drilling inventory in both basins, inventory that can generate significant value for many years to come. Second, takeaway solutions we've secured in both basins.
These include two significant sales agreements which will ensure our oil has reliable outlets at competitive prices for the foreseeable future. So in closing, I would like to thank all PDC employees but in particular the company's district operations.
Our team in West Texas continues to do an outstanding job of helping define the tremendous quality of the Delaware Basin assets. And in Wattenberg, our district team performed exceptionally well this past winter through some very challenging operating conditions.
Again, thank you to both teams. And with that, I will turn the call over to Scott Myers for a financial overview of the quarter.
R. Scott Meyers - PDC Energy, Inc.
Thanks, Bart, and welcome. I plan to keep things at a pretty high level as the first quarter was pretty much in line across the board aside from some improved pricing and some positive production results.
With production increase of 34% and Boe sales price increase of 20%, our overall sales increased 61% compared to prior year's first quarter. This sales growth directly led to our growth in net cash from operating activity to over $200 million for the quarter.
Net loss from the quarter was $13 million compared to net income of the quarter of $46 million from the first quarter of 2017. The primary difference was a loss of $47 million on our net commodity price risk management this year compared to $81 million of gains last year as well as $33 million impairment in Delaware leases in the first quarter of 2018.
Our net cash from operating activity, which is shown both on the table and the graph on the top right, increased 47% year-over-year to $205 million. Quickly touching on non-U.S.
GAAP measures. Please note that our reconciliations can be found in the appendix at the end of the slide deck.
Both adjusted EBITDAX and adjusted cash flow from operations increased around 50% compared to first quarter 2017 driven largely by the aforementioned increase in our sales. The graph on the right do a pretty good job of showing the steady sequential growth in each of these metrics on a quarterly basis.
Barring any dramatic shift in pricing, we expect this trend to continue, if not accelerate as we ramp our production in the coming quarters. Moving to slide 8.
We give an overview of our production cost both in terms of absolute dollars and dollars per Boe. The TG&P and production tax trends are moving as you would expect with an increase in production volumes and sales between periods.
So I'd like to spend a minute discussing LOE. For the quarter, LOE came in slightly higher than estimated in prior year's quarter primarily due to the impact of Wattenberg line pressures on production, continued investment in the Wattenberg air quality, and one-time expenses related to our Bayswater acquisition.
As you can see in the breakout of LOE per Boe by basin, the Wattenberg still sits at $3 per Boe. The Delaware decreased 30% compared to the first quarter of last year primarily as a result of the steady production increases.
As you will see in a minute, we still expect our 2018 LOE per Boe to be within our previously guided range of $2.75 to $3. As of March 31 we had a leverage ratio of 1.7 times and liquidity of $745 million, including $45 million of cash.
As a result of both an improved commodity outlook and strong first quarter results, we have reduced our full year expected 2018 outspend to $65 million from $90 million. We expect to cover this outspend with the proceeds from our recent Utica divestiture and Saddle Butte proceeds, both of which were closed in the first quarter.
As a result, we expect to exit the year with an undrawn revolver. Finishing up on slide 10, we show our 2018 financial guidance which remains unchanged and simply serves as a reaffirmation of our full year expectations.
We have received a lot of questions as how the company can maintain these price realizations despite the widening differentials. Lance will give you more detail on this in a few minutes.
With that, I'll turn the call over to Scott Reasoner for a closer look at our operating results for the quarter.
Scott J. Reasoner - PDC Energy, Inc.
Thanks, Scott, and good morning, everyone. Starting on slide 12, just a quick operational overview of the quarter.
I want to start by thanking our teams for delivering such a solid quarter. Our Wattenberg team continues to perform in a very efficient level and our Delaware team continues to mature and is gaining efficiency at a rapid pace.
The total daily production and growth rates on the left-hand side of the slide have already been covered. But here, we provide a quick look at our production by basin as well as our spuds and turn in line details for the quarter.
As you can see, Delaware volumes have surpassed 20,000 barrels of oil equivalent per day and now represent approximately 20% of total PDC volumes at a strong 47% crude. Moving to slide 13, we give an overview of our first quarter capital investment and full year expectations.
As you can see, we invested approximately $250 million in the first quarter which was right in line with our internal expectations. Obviously, the quick math would suggest full year capital of around $1 billion.
However, I want to stress two things. First, our capital program is weighted towards the first half of the year.
This is consistent with the last few years and, I'll reiterate, in line with our internal expectations. In fact, we had a handful of wells come online about two weeks earlier than expected, meaning we bore the full cost of these wells with little to no impact on production and cash flows in the quarter.
The second point to mention here reiterates what Bart opened with in that we expect to keep a close eye on our efficiencies throughout the year, and at this point we plan to manage our 2018 capital program to stay within the range of $850 million to $920 million. On the right hand side of the slide, I want to point out two key items.
First, we're getting closer to DCP's Plant 10 completion that we anticipate will be a key catalyst for our Wattenberg production in the second half. And second, we invested $12 million in our Delaware Basin midstream assets in the first quarter.
I'll give a bit more color on the value-add of this investment in a few slides. Slide 14 gives an overview of our quarterly production and lifting cost profiles.
Starting with production, our Delaware outperformance for the quarter outweighed a couple of issues in the Wattenberg. The impact of high line pressures was relatively consistent with what we had expected at the outset of the year.
However, plant downtime and freezes did have an impact. Net-net, we're pleased with where we sit today and expect a fairly robust, relatively linear growth trend for the remainder of the year.
In terms of LOE, Scott already gave pretty good color on this so there's not much to go over. As mentioned, full year LOE per Boe is expected to fall within the range shown as a result of increased volumes with a relatively stable cost structure.
Shifting gears, I want to once again spend a few minutes on the continued execution we are delivering in the Delaware. As you can see, our daily production of over 20,000 barrels of oil equivalent per day is an increase of nearly 30% compared to the fourth quarter last year.
This is largely due to the continued strong performance demonstrated by our Buzzard and Grizzly wells. I'll add that while we did have seven turn in lines in the quarter, all seven were in the second half of the quarter, so we expect they will have much more of an impact next quarter.
More on these wells in a minute. On slide 16 we give an update to the cumulative production of the Buzzard and Grizzly wells, and as you can see they continue to track very well through 100 to 150 days or so.
For instance, the Buzzard North and XRL Wolfcamp A well has produced about 400,000 barrels of oil equivalent in the first five months online or about $16 million worth of production. With oil accounting for approximately 70% of this well, you can see we're close to 300,000 barrels in the first five months, a truly remarkable well.
Looking forward, we're drilling the last two wells on our eight-well Grizzly Bear pad. This pad includes six wells testing 12 wells per section equivalent in the Wolfcamp A in a half section as well as our first Wolfcamp C well in Block 4.
As a reminder, we currently do not assume any Cs (00:16:15) in Block 4 in our current count. Just to manage expectations, if you think about completing and turning in line an eight-well pad, we're really looking at November of this year as the earliest to have a reasonable amount of data to give some commentary on these results.
Before moving to the Central area, I want to talk about some of the midstream assets we've developed through our continued investments. As you all know, we plan to invest an estimated $20 million on an oil gathering system in Block 4 this year.
But for now, I want to focus on our water distribution system in the area. It's important to note that through water management we're really able to control our own destiny in terms of scheduling and operations as well as providing the potential for LOE or capital savings.
The map on the right shows a rough outline of our current infrastructure. You can see we currently have one saltwater disposal well in the area with another planned this year as well as access to several third party saltwater disposal wells.
We also own a couple of freshwater supply wells and pits in addition to our recently completed treated water pits. Quickly walking you through the process we're implementing here, imagine produced water flowing through the thin blue lines from the wellhead to the thick blue gathering line.
Water then flows to our treatment facility where it can be recycled and stored in our treated water pits and it is now ready to be sent out on the distribution lines shown in red to the next frac job. Any excess water can be disposed of into a PDC or a third party water disposal well.
On a couple of recent wells, we used 20% treated water and we plan to use even more treated water on the upcoming completion of the Grizzly Bear pad. Our long-term goal is to use a majority of recycled water in the future.
We see this type of infrastructure as being a tremendous value-add as we continue to ramp up. We are, across all of our Delaware operations, putting nearly all of our produced water on pipe.
This is critical to efficiency, particularly when trucking in the basin is at a premium. In our Central area on slide 18, we give some color on the recent turn in lines from the quarter.
These wells are in the northern part of our Central area shown on the map. As I mentioned, these wells were all turned in line in the back half of the quarter and are showing strong results, albeit with around 40 to 60 days of production and still very early in the flowback process.
Among the wells, the three-well Greenwich pad consists of two Wolfcamp As and one Wolfcamp B and are all MRLs. And the Sunnyside and Old Monarch are both SRLs with one Wolfcamp A and one Wolfcamp B landing zone.
All five wells are currently producing at an average rate between 1,000 and 1,400 barrels of oil equivalent per day with crude averaging approximately 55%. We view these wells as a good indication of the strong resource in our North Central area.
I'll now turn the call over to Lance Lauck to give more detail on the economics as well as our current marketing and midstream overview in each basin. Lance?
Lance A. Lauck - PDC Energy, Inc.
Thanks, Scott, and I want to start this last section of the Q call with a focus on our marketing takeaway arrangements in both the Delaware and the Wattenberg. Over the last couple of months the Midland/Cushing differential has widened due to crude oil takeaway constraints out of the Permian Basin.
This tightening is projected to continue until additional pipeline capacity is in service in the second half of 2019. Despite the current takeaway constraints, we believe that PDC is well-positioned to manage through this short-term tightening while delivering strong, value-added growth from our Delaware basin assets.
Before I speak to slide 20, I want to make sure we share the two key objectives of PDC's marketing strategy. The first is to ensure takeaway capacity for our future development plans, and the second is to realize competitive netback pricing in both the short-term and the long-term.
We believe both these objectives are being achieved in our marketing plans. Let's now look at slide 20.
First of all, while we're experiencing very strong oil growth in 2018 for the Delaware, the Delaware still only represents about 20% to 25% of our total corporate oil production for 2018. So the impact of a widening differential in Delaware gets blended in with our overall corporate oil differential which minimizes the overall corporate impact to the company.
PDC's solid marketing position in the Delaware Basin is due to the outstanding work of our marketing team that has taken a proactive approach to seeking out long-term sales that assures takeaway capacity while also providing competitive netback pricing. This slide highlights our two key oil marketing initiatives in the Delaware Basin.
First of all, approximately 50% of our projected 2018 Delaware crude oil volumes are directly connected on pipe to Oryx Midstream. This pipe connection provides certainty of flow to Midland and Crane delivery points.
Additionally, we are building out our own crude oil gathering system in Block 4 that we anticipate will gather all of our crude in Block 4. We've allocated proximately $20 million in our 2018 capital budget for this investment.
We project that our percent of oil on pipe will increase over time. The balance of our oil production in Delaware is trucked typically to oil pipelines that connect to Midland.
Our second initiative is our recently executed firm sales agreement with a large international energy company that provides firm physical takeaway capacity out of the Permian Basin to a Corpus Christi terminal. With this new contract, PDC will realize export market pricing with international Brent-based exposure.
The key terms of the contract include five and a half-year agreement which represents 85% of our projected crude oil volumes beginning in June 2018 through calendar year 2019. This is the period where takeaway capacity is tight in the Permian Basin and it's also a timeframe that we typically provide for our corporate outlook.
We expect to realize, after deducting all transportation fees, between 88% and 92% of NYMEX on all of our Delaware Basin oil volumes from June 2018 through calendar year end 2019. Let me now provide some insight into years 2020 through 2023 of the firm sales agreement.
While we can't go into the details of the contract, we currently anticipate that our realized oil price in this contract is expected to be competitive with projected realized prices at Midland for years 2020 through 2023. This analysis is based on current market pricing for future Brent and WTI oil prices as well as Midland basis differentials for years 2020 through 2023, and it includes all associated transportation fees.
We're very pleased to have executed this new contract as we believe it achieves our two key marketing objectives. It ensures takeaway capacity for our future development plans and we expect to realize competitive netback pricing both in the short-term and the long-term based upon the current market forecast.
Let's now look at our gas marketing summary in the Delaware Basin on slide 21. Again, like our Delaware oil production, our 2018 gas volumes in the Delaware are projected to represent about 20% to 25% of total corporate gas volumes.
Let's start with the Eastern area and South Central areas. Eagle Claw processes our gas and delivers it back to PDC at the tailgate of their plant for PDC to market.
We have two firm agreements in place that provides flow assurance on these volumes and minimizes future Waha exposure. First, we have a 40 million Btu per day firm transportation agreement from the plant tailgate to the Waha Hub.
Then secondly, we have another 40 million Btu per day sales agreement from Waha to the Houston Ship Channel with a fixed differential through 2019. As we continue to ramp-up production, we'll continue to work on securing additional firm transportation capacity.
In the North Central area, ETC is responsible to purchase our gas at the wellhead and markets gas under ETC-owned assets. Let's now shift gears to the Wattenberg and take a look at our natural gas and crude oil marketing arrangements there.
For reference, our Wattenberg assets are projected to produce about 75% to 80% of our total natural gas and crude oil in 2018. First of all, our gas is gathered and processed by our midstream providers.
DCP is projected to process about 75% of our Wattenberg gas in 2018 while Aka Energy along with offloads to Anadarko is expected to process about 25% of our gas. Our marketing arrangements with both DCP and Aka are based on percent of proceeds contracts which allocate a certain percent of the revenues from natural gas and NGLs to the midstream provider in exchange for their gathering, compression, processing, and marketing of the natural gas and NGLs.
From where we sit today, we believe we are now well-positioned for the long-term in the Wattenberg with the recent DCP Plant 10 and Plant 11 expansions which are on track to increase DCP's capacity by nearly 50% by mid-2019. Additionally, discussions continue on Plant 12 for midstream infrastructure growth in the basin.
We continue to work closely with DCP to define our long-term volume growth from Wattenberg so they can best plan for future midstream expansions and takeaway capacity from the basin. And then finally on the crude oil side, effective May 2018 we recently entered into a five-year firm oil transportation agreement with Tallgrass Energy.
The key terms include 12,500 barrels per day delivery on their Pony Express Pipeline to various refinery destinations into Cushing, Oklahoma. Let's look now at slide 23 in our portfolio value creation.
This slide highlights the strong, long-term value creation potential of PDC's drilling inventory. The updated economics presented today are based on MRL-equivalent lateral links which represent on average about 7,500-foot laterals.
Our projected commodity price outlook and per well capital cost estimates are provided in the footnote below. We're not only providing an economic breakout of the current inventory contained in each of our five major drilling focus areas, but we're also showing how it rolls up into our consolidated portfolio.
Each of the five bar graphs represent the per well weighted average economics for all our current inventory in that area. So for example, the per well economics of Block 4 in Delaware are based on approximately 250 locations that include both the Wolfcamp A and the Wolfcamp B.
As the bar graph projects below, our inventories within our Block 4 and North Central areas at Delaware are expected to provide our highest NPVs per well along with very solid rates of return. Our Wattenberg assets in Kersey, Plains, and Prairie are projected to deliver some of our highest per well rates of return with very predictable and repeatable results.
If we look on a total portfolio basis, the company estimates that it has approximately 1,950 total gross locations in our inventory. Let me highlight a couple metrics of our entire portfolio based upon a weighted average well basis.
First, we estimate our F&D to be less than $8 per Boe. And secondly, and very importantly, we project our total portfolio to have a weighted average rate of return of approximately 70%.
We continue to focus on improved efficiencies in both assets. For example, we're still in the very early innings in Delaware.
And secondly, our Prairie and Plains economics are currently based on industry data at this point. We look forward to utilizing our internal completion designs to determine the best potential impact in growth and opportunity for these locations.
Finally, our teams continue to focus on building out additional inventories especially in the Delaware through additional downspacing and new intervals. We're very pleased with where the company is positioned today.
This final slide highlights the key attributes that PDC expects to deliver in 2018. We believe that each of these operational and financial components work together towards growing long-term shareholder value.
Our focus is on returns, results, and responsibility; and we'll continue this theme over the long-term. The key driver of value is our organization, and we're very thankful to have such a strong team at PDC.
With that, I'd like to turn it over to the operator for Q&A.
Operator
Our first question comes from Asit Sen with Bank of America Merrill Lynch.
Asit Sen - Bank of America Merrill Lynch
Thanks. Good morning.
I just wanted to follow-up on the Plant 10. When Plant 10 comes online or ramps up, how do the volumes get prioritized between different operators?
And on that, when Plant 11 and Plant 10 is on, does it resolve the line pressures completely or situation of line pressure completely in 2019? And could you also comment on the talks that are progressing with respect to DCP?
Scott J. Reasoner - PDC Energy, Inc.
This is Scott. I'll start and I think Lance will probably have some color to add to this as well.
Looking at Plant 10 and the idea that we're expecting it to come on in the third quarter, we're seeing our volumes ramp up according to the plan that I described which is fairly significant increases by quarter, well I guess linear if you want to call it that. And the idea of the allocation between operators is it really is the strongest wells get into the system and that's across all the operators.
At this point we do have some management of the system flow. But I think once they turn Plant 10 on that management approach where they're managing the different companies to the volumes will go away and it'll be back to the normal operating procedures which really lets anybody – the strongest wells get in the system is the best description.
Also, the wells more in the center of the field have an advantage because they're, many times, closer to the compressor stations. When you put Plant 11 on with it, we would expect pressures to come down and that'll be a tremendous benefit to the wells particularly as we have a significant number of the old vertical wells shut in at this point and they're obviously waiting for that lower line pressure to come on.
We expect to see them come on with Plant 10 but we feel like we'll get full flow when Plant 11 comes on.
Lance A. Lauck - PDC Energy, Inc.
Asit, let me just speak a little bit to the discussions with DCP. And I think the thing that we really like about the ongoing relationship with them is that we are meeting frequently really at all levels in the organization, and we spend a lot of time putting together various projections of what our future growth looks like in the Wattenberg.
So we give them a range of projections and volumes so that they can then take that, and along with other work that they do with other producers in the field they get what they believe to be more of an aggregate view of the growth from the basin on acreages that are connected to their system. And so from that, they're able then to do all of their hydraulics and all of their different modeling with the plants and processing and compression within the field and then put forth their plan for takeaway from the basin in their plant design and construction.
So I would classify this relationship as very strong and very much working together to the benefit of both parties in the basin.
Asit Sen - Bank of America Merrill Lynch
Thanks, Lance. And actually I have a question for you.
Great update on the midstream strategy. But just wondering if I could get your update on thoughts surrounding M&A, whether larger deals or smaller bolt-ons, where is your head at?
Lance A. Lauck - PDC Energy, Inc.
Yeah. So we continue to look at the sort of the smaller bolt-on opportunities in both basins as well as look at trades in both basins.
In fact, we have a smaller-sized trade that we executed post the first quarter here with another party in the Prairie area of Wattenberg. And I would just sort of think of those smaller trades as something that is more of our normal course of activity that our teams are doing an outstanding job on just to continue to drive that efficiency with the longer laterals and the ability to gain more control of the timing of development.
As far as the bolt-on deals, similar to the recent Bayswater deal that we closed on in January, we'll continue to look and are in the market looking at those opportunities, and we're definitely in the deal flow and we're seeing a good deal flow from that. So our teams are very focused on that.
We recognize that it's important to make sure that we find opportunities like that to continue to build out our longer-term inventory for our company. And so we've got a good process in place and that's something that we'll continue to do as we go forward, always having a keen focus on our balance sheet in any of the activities we do.
Asit Sen - Bank of America Merrill Lynch
Thanks. Appreciate the color.
Operator
Our next question comes from John Nelson with Goldman Sachs.
Barton R. Brookman - PDC Energy, Inc.
Hi, John.
John Nelson - Goldman Sachs & Co. LLC
Good morning and congratulations on the update.
Barton R. Brookman - PDC Energy, Inc.
Thank you.
John Nelson - Goldman Sachs & Co. LLC
I was hoping for, first, just a clarification I guess on slide 22. I think it was in your prepared remarks and I just missed it.
But are the Block 4 Wolfcamp A only or is that longer laterals that get you to the 250?
Lance A. Lauck - PDC Energy, Inc.
Yeah. So John, this is Lance.
Yeah, the 250 wells in inventory are 1.5-mile equivalent, so some of them are going to be 2-milers; some are going to be 1-milers, but includes both the Wolfcamp A and the Wolfcamp B in that inventory.
John Nelson - Goldman Sachs & Co. LLC
That's helpful. And then could you just remind us what the working interest levels are at Kersey, Plains, and Prairie on average?
Lance A. Lauck - PDC Energy, Inc.
I would say on average, as you look across those three areas of Wattenberg, we're approximately in that 80% working interest range. It's going to vary a little bit.
It can be at 85% at certain times. But when we think about the longer-term, we think it's more in that sort of 80% working interest range.
R. Scott Meyers - PDC Energy, Inc.
In the Kersey area, it's definitely in the higher end of the 80s. In the Prairie area, it would be a little bit lower.
So the average, Lance has it. But as we execute some of these smaller swaps, we'll be able to raise that working interest in the Prairie area.
Lance A. Lauck - PDC Energy, Inc.
Right.
John Nelson - Goldman Sachs & Co. LLC
That's great. And then a less detailed question.
Go back to the prior commentary on DJ Basin midstream debottlenecking and your comments on you expect the start of Plant 11 to be really when you see line pressures drop. I think we've also seen some announcements from I think Discovery and Outrigger planning to bring on some processing capacity in 4Q and 1Q.
Just curious if you're aware. I know DCP is kind of dedicated to your acreage, but if there is a link between those two operators in the DCP system, that could potentially maybe alleviate some of those pressures sooner.
Scott J. Reasoner - PDC Energy, Inc.
John, this is Scott. Again, I think Lance will add on to this when I finish.
But with respect to line pressures, we definitely expect them not only to come down with Plant 11 but Plant 12 and Plant 10. All three plants will have an impact on line pressure.
The key right now is that we've got very high line pressure, I would call it, in the Wattenberg and that Plant 10 is critical to bringing those line pressures down and obviously making our guys' lives easier out there. It's a complex project when you have the pressures that we're dealing with right now.
I will also say that those other plants, and Lance will comment more on our ability to get in them or whatever, but I will tell you irrespective of who ends up putting gas on there, it does help us because it takes gas off of these other systems. So if it's not us and it's someone else, definitely has an impact on our wells because that gas doesn't have to go in through a DCP or Aka or an Anadarko type system.
Lance A. Lauck - PDC Energy, Inc.
Yeah, and the only thing I'd add to that is that with Discovery and Outrigger projected and actually being in the basin with their gas plants and processing, I mean, what it provides is for those producers that have the ability to provide gas to those plants, just as Scott has said, to get gas off of other systems to where it improves the ability for those that are on, for example, the DCP system and other systems to produce gas from our wells. So more capacity for plants in the basin is helpful through the entire basin and all the producers in the area.
John Nelson - Goldman Sachs & Co. LLC
I understand. So I think if I heard you correctly, even if there isn't a direct link to the DCP system, if other operators have access to multiple systems, you could still potentially see a benefit?
Lance A. Lauck - PDC Energy, Inc.
That's correct.
Scott J. Reasoner - PDC Energy, Inc.
Absolutely.
John Nelson - Goldman Sachs & Co. LLC
Great. Congrats again on the quarter.
I'll let somebody else hop on.
Operator
Our next question comes from Welles Fitzpatrick with SunTrust.
Barton R. Brookman - PDC Energy, Inc.
Hey, Welles.
Welles Fitzpatrick - SunTrust Robinson Humphrey, Inc.
Hey, good morning. Not to beat a dead horse on this midstream stuff, but I think the last question was important in the sense that it looks like in 1Q between Latham (00:40:52) and Kiowa and then of course in 3Q between O'Connor, the Latham (00:40:56) expansion, Kiowa expansion, and Pierce (00:40:58), I mean, you're talking something like 1.2 Btu of capacity to the basin.
Was that processing coming on in 1Q and hopefully the 3Q stuff coming on before the worse of summer, do you think we ever get back to the kind of 300 psi type pressures in 2019 that we've been seeing recently or do you think that all of that capacity coming into the basin, whether on DCP or not, is enough to alleviate it for the foreseeable future?
Scott J. Reasoner - PDC Energy, Inc.
Yeah. Welles, this is Scott.
It's a good question that we are constantly trying to evaluate. I think a lot of it comes back to we would love to see Plant 10 come online before we get a real feel for the impact of it.
At the same time, we're watching our peers out there and what they're planning to do. Those all influence what will happen in between the time when Plant 10 comes on and Plant 11 comes on.
We're obviously expecting lower line pressures this year and some substantially lower line pressures this year because we projected higher volumes, and I think that says a lot about where we expect things to go. When we get into 2019, that's still something we're wrestling with in our heads.
I would say the best way to look at this, for us, is to say let's look at Plant 10 coming online, and then I think we'll have a pretty good feel after a couple months of that what's going to happen in 2019. I'm hopeful that we don't see the kind of line pressures we're seeing right now because it is a difficult effort to stay ahead of that.
But if they are, I think they're going to be relatively short and that Plant 11 coming on right on the heels of that is why I think it'll be a short period of time. DCP has got a definite plan to get that plant done and we're obviously in direct contact and consistent contact with them making sure we understand the status of it.
Barton R. Brookman - PDC Energy, Inc.
Welles, this is Bart. Let me see if I can just add a little color to this because I know our discussions with DCP, which have been extensive, I think we have a really good feel of how they're looking at this with these multiple expansions.
They have contractual obligations on line pressure and they are hydraulically engineering this system based on the forecasts that the producers are giving them, and that includes processing, compression, and in-field gathering pipe, and those three components are all engineered with the goal of getting our line pressures back to normal levels. So I think, to Scott's earlier comments, you're going to see the first step in line pressure reduction with Plant 10.
Hopefully with Plant 11, we're going to get close back to normal and then additional discussions around processing capacity are going to give us that long-term capacity for us to fully develop our resource potential at the pace that we pick I think as we go into any facilities past Plant 11. So hopefully that provides a little clarity around all that.
Welles Fitzpatrick - SunTrust Robinson Humphrey, Inc.
No, that's extremely helpful. I mean, it seems like it's something like 50% additional year-over-year to basin capacity by 3Q 2019, and obviously the publics aren't growing at that pace so, knock on wood, it'll be behind everyone.
You guys list the other locations in the presentation. Can you talk about where within the two plays those are and do those have some sort of minimum IRR hurdle rate to make it into that count?
Lance A. Lauck - PDC Energy, Inc.
So Welles, the other areas that are represented by the 225, for example, if you look at our Wattenberg map what you'll find is the three core areas and then you'll see the yellow acreage outside of those core areas, and slide 22 is a good map to look at on that. So what we're talking about is all the acreage that's outside those three areas and the wells that are in that area that constitutes a big portion of that as well as there's some positions also that are in other areas of the Delaware Basin.
There's about 50 in the Delaware and about 175 that are in the Wattenberg, but primarily the Wattenberg is in those areas that are outside the three core areas. And as you think about trades and stuff going forward, this is where the opportunity is for us to say do we create a fourth area and consolidate around that acreage that's kind of in the Southeast area or do we trade out of that and build positions within the other areas that we have already constructed, those three out there.
Welles Fitzpatrick - SunTrust Robinson Humphrey, Inc.
Okay, so those locations aren't necessarily any worse than the other stuff, it's just maybe non-Block 4 Eastern acreage or unnamed Wattenberg middle core. It's just not quite as blocky?
Lance A. Lauck - PDC Energy, Inc.
That's correct.
Barton R. Brookman - PDC Energy, Inc.
Yeah. In fact, some of it is scattered as it is.
Well some of it I think is extremely prolific based on some of the data. It's just not as blocky for us right now, so we've got to tactically think about how we swap or acquire some bolt-ons so that we can pursue 1.5-mile and 2-milers.
Welles Fitzpatrick - SunTrust Robinson Humphrey, Inc.
Okay, and then just one last one to hit on on politics. Kennedy seems to continue to be gaining momentum, got the nod from Salazar.
Do you guys have any updates as to kind of how the industry might be thinking about that, any polling numbers that you might be privy to as to her chances over Polis in late June?
Barton R. Brookman - PDC Energy, Inc.
No, I don't think we have any updates on that. I think they're both viewed as strong candidates right now, and she obviously has made some great strides here in the last month.
And you've got really few very strong candidates heading into the primary on the Democrat side and same thing on the Republican side, so it's going to be an interesting June as they duke it out. And then I believe at the end of June we've got the primaries and then by the 4th of July we're going to know the Democrat candidate and the Republican candidate.
And then Welles, we just have to see where that goes. We have spent some time with all the candidates and we know that they – right now, their platforms, they're not out there with a big anti-energy platform, so we feel good about that.
But again, we've got to let this get through the primary, get into the main election, and then we're going to know in November. But I think you can expect more accurate polling here over the next six weeks to hit the wire and you're going to see some trends and some leaders.
Welles Fitzpatrick - SunTrust Robinson Humphrey, Inc.
Wonderful. Thanks so much.
Operator
Our next question comes from Park Carrere with Scotia Howard Weil.
Park Carrere - Scotia Capital (USA), Inc.
Hey. Good morning, guys.
I appreciate the added midstream color. Could you maybe go into a little more detail on the optionality you have on the gas side in the Delaware to get that gas out of the basin and maybe what kind of stage in negotiations you're in right now?
Lance A. Lauck - PDC Energy, Inc.
Yeah. So when we think about optionality for gas in the Delaware, basically if you focus on sort of the Eagle Claw area, and that's all of our Eastern area and it's also the South Central area, there are multiple pipes coming out of the tailgate of the plant of Eagle Claw that take it to various locations that we can get first off to the Waha Hub, and then there's several pipes on the Waha Hub that can get us to the various markets.
So we've done a lot of research on this and we believe, again, as we continue to grow in the Delaware that we will be able to find the transportation for our gas to get to market.
Park Carrere - Scotia Capital (USA), Inc.
And is there something you all might have an announcement, kind of more concrete, longer-term agreements in 2018 or is it just kind of ad hoc, as-needed basis?
Lance A. Lauck - PDC Energy, Inc.
Well that's something I think that we will continue to add to over time and that's what we have to – is implied there by the slide that talks about actively pursuing additional capacity for gas out of the basin. We have talked with various parties and had various discussions and all.
So it's things that we'll add to as we forecast out our development plans in the Delaware and see what volumes are required for transportation to the markets. And so we'll do that kind of as we'll layer that on probably more over time as we continue to ramp-up growth in the basin.
Park Carrere - Scotia Capital (USA), Inc.
Okay. So it doesn't seem to be an issue or a worry for you?
Lance A. Lauck - PDC Energy, Inc.
No. We recognize that the gas lines are growing in the basin and we recognize that takeaway is key and very important, but we also recognize that we've got a lot of ongoing work that we've been doing to various parties to ensure that our gas will flow.
Lance A. Lauck - PDC Energy, Inc.
Great, thanks. And talking a little bit about capital allocation in 2019, and these are the cash – obviously I think you all's budget was predicated on $55 oil.
How do you think about that kind of growing free cash flow stream and what you all is planning to do with it?
Barton R. Brookman - PDC Energy, Inc.
So as far as capital allocation, I think as we're heading towards next year our starting point would be to keep to three. We've really gotten nice operational balance right now, three rigs in Delaware with one full frac fleet, and that activity is pretty balanced; and in Wattenberg with three rigs and one frac fleet is almost perfectly balanced.
So I think that's our starting point. I think you can expect the capital spend in Wattenberg to be similar, maybe a little bit up due to maybe some cost increases.
And then in Delaware we probably have two things that may bump the capital in 2019 up a little. First and foremost, as we're getting better and better at what we're doing there, our drill times are improving, our frac efficiency is improving.
So I would hope and predict that we will drill a few more wells with the three rigs next year, and that will all be a positive story from a capital efficiency standpoint. But if anything, you might approach the – we've got $500 million this year in Wattenberg and $400 million in Delaware, so you may approach pretty close to a 50/50 mix on capital allocation.
Then as far as our cash flow, and I think we've consistently been in the market with this, we first have to set our budget. I mean, we look at prices.
We anticipate we'll have additional cash flow. I would anticipate that could be anywhere from $150 million to $200 million, and right now we'll look at additional capital spend opportunities.
Obviously at some very strong rates of return, we feel that's the best thing we can do for our shareholders. We'll also look at what Lance talked about earlier, bolt-on acquisitions in areas where we could build our inventory.
And then we get a lot of questions around dividends and buybacks, and I think our position right now that's probably a lower priority for the company as we go into next year.
Park Carrere - Scotia Capital (USA), Inc.
Great. Really appreciate the time.
Thank you.
Operator
Our next question comes from Mike Scialla with Stifel.
Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
Yeah. Good morning, guys.
Just wondering on your midstream. You're gathering about 50% of your oil in the Delaware, you said, with Oryx and you're working on that Block 4 midstream buildout yourself.
More than the timing of when you think that will be completed and what is that going to do in terms of how much of your oil will be gathered on pipe at that point and what kind of cost savings do you see over trucking there.
Scott J. Reasoner - PDC Energy, Inc.
I guess we're really excited. We've got the oil pipe started at this point and we'll be connecting a number of wells out there, including the Grizzly pad that we've not turned online yet and we haven't fracked yet, so that'll be added to the system.
We're expecting that pipe to be completed in the fourth quarter, Mike. And I think with that, our volumes will continue to move up.
Particularly like I've said, we'll be turning online that Grizzly pad probably, say, sometime in July-August. Something about that timeframe feels right for me right now, and you'll see oil obviously going by pipe up significantly.
And then through the year it'll depend a lot on how the completion process goes and where that goes. But we're seeing oil increase.
It's a key for us to be successful. We feel like to continue to add to that pipe as we add additional wells in Block 4.
And they're such prolific wells that it was a necessity. There's not really an option there.
They're enough to drive the volumes up here recently. It's been substantial.
So we're excited about getting it online and getting a chance to start utilizing it in that fourth quarter timeframe.
Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
Any idea on the cost savings trucking versus putting your oil on pipe?
Lance A. Lauck - PDC Energy, Inc.
Mike, we don't plan to share those details. But clearly we've stated obviously if it could go on the pipe it's a lower fee than if you're trucking it.
Scott J. Reasoner - PDC Energy, Inc.
And I think right now, Mike, when you look at trucking being at a premium back to the comments I made on water, it's a substantial cost savings as those truck costs vary and you guys I think hear those varying around multi-dollars movement per barrel. It's definitely more consistent and definitely something we appreciate over the long-term.
Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
Okay. And wanted to see if you could talk too about the – you mentioned the impairment you took on the leases in the Delaware.
Can you say where those were, how many acres? Anything more on that?
R. Scott Meyers - PDC Energy, Inc.
Yeah, sure. It was about 1,000 acres and it was in our Fortuna acreage as we called it.
We had a well – maybe, Scott, if you want to give a little color on that – but there was 1,000 acres in the Culberson portion of our Fortuna, close to our North Central but we were having an issue with the well.
Scott J. Reasoner - PDC Energy, Inc.
Yeah. We ended up having a well that just had some downhole problems and it was not going to be economic to recover.
Barton R. Brookman - PDC Energy, Inc.
Just, Mike, none of the 450 wells that we stated in our inventory were on this acreage.
Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
So no impact on drilling inventory with that being written-off?
Barton R. Brookman - PDC Energy, Inc.
That is correct.
Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
Okay, and last one. Just kind of surprised actually that you did an agreement with Tallgrass.
I thought there was quite a bit of excess capacity on the oil side of the DJ. Any thoughts about the factors behind that decision?
Lance A. Lauck - PDC Energy, Inc.
I think, Mike, from our standpoint couple things that kind of come into mind for the Tallgrass opportunity. Number one, it's a long-term, five-year contract for us and it locks in some prices that are very competitive of what we're receiving today.
So we like what we see today. We thought let's go ahead and lock that in for five years in that same type of a range.
And then keep in mind, too, that 12,500 barrels a day is really just a slice of our overall gross operated oil production as you get out over the next five years within Wattenberg. So we just thought it'd be good to go ahead and put in a slice in because we like the price.
It's just 1% of our future production from the Wattenberg and just wanted to lock that in. It's just part of how we put forward our risk management from the pricing side.
Barton R. Brookman - PDC Energy, Inc.
Mike, I think we are...
Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
Sorry. Go ahead, Bart.
Barton R. Brookman - PDC Energy, Inc.
Yeah, just a quick add. I think we also recognize with the substantial PUD inventory across the core Wattenberg, particularly for a couple of the larger operators, when DCP is up and running and they get these plants and then earlier discussion around all these private equity-backed small adds of processing capacity, over the next year or two you're going to have a shift of hopefully sufficient midstream capacity, and that is also going to encourage what we think is expanded rig counts in the basin if oil holds over anywhere over $55 a barrel.
So I think this is a good tactical move on our part given we recognize probably rig counts have been limited in this basin over the last couple years because of midstream constraints. So I think, overall, cost competitive assurance for PDC and I think our team has done a good job of looking out the next five years on all this and trying to anticipate it.
So I think it's a good deal for us.
Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc.
Got it. That makes sense.
Thank you.
Operator
Our next question comes from Brian Corales with Johnson Rice.
Brian Corales - Johnson Rice & Co. LLC
Good morning, guys. Most have been answered but I think you all either were completing or have completed a couple wells outside of Block 4 in the Eastern area.
One, do you have anything to comment there about how those are doing? And then, two, are you all expecting those to look like Block 4 wells?
Scott J. Reasoner - PDC Energy, Inc.
Brian, this is Scott. As Bart stated in his comments, they're performing as we expected, and we weren't expecting performance quite at the Block 4 level but we're seeing good production out of them.
And as far as GOR, they got a little more gas to them but we've still got plenty of oil to recover there. So we're excited about those and it confirms some of our thoughts about the area.
We're starting, as you can see from the map, we're starting to get wells across much more of our acreage position and we're learning a heck of a lot about what we have. But at this point, we're excited about those two wells and we'll continue to operate in that area.
Brian Corales - Johnson Rice & Co. LLC
All right, guys. Thank you.
Operator
Our next question comes from Oliver Huang with CPH (sic)[TPH].
Oliver Huang - Tudor, Pickering, Holt & Co. LLC
Morning, everyone.
Barton R. Brookman - PDC Energy, Inc.
Hi, Oliver.
Oliver Huang - Tudor, Pickering, Holt & Co. LLC
On the oil firm sales agreement and guidance for 88% to 92% of NYMEX realizations, is that based off the $57 deck that you all kind of guide to or is that closer to where strip is today?
Lance A. Lauck - PDC Energy, Inc.
It's closer to where current markets are today. Both for WTI, so that would be the NYMEX strip price for WTI and for Brent.
Oliver Huang - Tudor, Pickering, Holt & Co. LLC
Okay. And to the extent you're able to talk about it, is the tariff on the agreement a fixed cost or is there a potential for this to kind of shift around with movement in oil prices or differentials?
Lance A. Lauck - PDC Energy, Inc.
Yeah. So we can't go into the various terms of the contract, but what we wanted to do is provide the summary percent of NYMEX and that's what we're doing with the 88% to 92% through 2018 and 2019.
Oliver Huang - Tudor, Pickering, Holt & Co. LLC
Okay, perfect. And for my second question, know you all have provided guidance for how 2019 could look in a $55-ish environment, and this might be a difficult question to answer.
But just from a longer-term perspective, could you provide some color on what you all think the right rig or well count that would be needed to optimally develop your acreage, balancing infrastructure and capital efficiency in each of the Delaware and the Wattenberg?
Barton R. Brookman - PDC Energy, Inc.
That's a lengthy question but let me start and then, Lance, if you want to jump in here. And I think as we look at our capital allocation and our rig pace, we obviously look at our cash flow-positive overspend levels.
We anticipate we're going to be cash flow positive next year. We look at our operating pace for our operating teams.
And as I said earlier, we try to balance that against – having a consistent frac fleet kind of balanced with the rigs so you're not bringing in frac fleets and then releasing them. We also prefer consistent rig pace over substantial periods of time because I think our drilling teams get into a routine.
Then we turn and we look at midstream capacity, and obviously we've got to give consideration to that. It's part of the reason we backed off on rig counts in the Wattenberg as we waited for expansions.
And then we put that all in a bucket and look at the balance sheet strength and then we look at the growth of the company, and we've been very fortunate the last few years. That formula has resulted in us growing the company substantially year after year.
So I think the thing we won't do is overgrow the company, okay? I think we've got to be careful.
And as we said earlier, the three-rig and three-rig right now, we're in the market with a 30% to 40% production growth next year. That's a pretty aggressive tick to be able to maintain your operating pace and grow the company that significantly and the balance sheet.
So I think the answer to your question right now is kind of – right now I'd look at it as a steady state pace we're at right now. And obviously we've got to get to our budget cycle which starts in September-October timeframe.
We're going to dedicate an incredible amount of effort into understanding – I think the big moving component for the company right now is our Delaware, and the results are terrific. And as Lance presented on his second to last slide, we've got some incredible results, particularly in Block 4 but also in the North Central area and just north of Block 4 in the Eastern side, and we've got to look at all of that.
Obviously our goal is to drill the best wells first. But I don't know if there's any operator you have the luxury of doing that every day, day-in, day-out.
We also have to take into consideration all the other things I just talked about. You have anything else you want to add to this?
Yeah.
Lance A. Lauck - PDC Energy, Inc.
No, it's a great summary. I mean it all gets down to projecting forward where we're driving value-added growth and all the time watching our balance sheet, looking for opportunities to tactically add to our inventory to continue to grow the NAV of the company and also working very good on the hedging side and the takeaway side to make sure we have a surety of takeaway and competitive netback pricing for our commodity.
So all those things work together to drive value going forward.
Oliver Huang - Tudor, Pickering, Holt & Co. LLC
Thanks. Appreciate the color and congrats on the quarter again.
Barton R. Brookman - PDC Energy, Inc.
Thank you.
Lance A. Lauck - PDC Energy, Inc.
Thanks.
Operator
Our next question comes from Paul Grigel with Macquarie.
Paul Grigel - Macquarie Capital (USA), Inc.
Hi. Lance, one more detail just on the midstream agreement then from the Permian.
Does the volume scale beyond 2019 to go along with your growth or would you need to look to other sources for offtake there?
Lance A. Lauck - PDC Energy, Inc.
Well if you look at our note 13 in the back of our Q, it gives the volumes, Paul, of our committed volumes on this opportunity that we have on this firm sales agreement that we have. I mean, clearly, if you look at years sort of 2020 through 2023, those volumes are fairly steady throughout that period of time.
And as you look at the company's production, we're going to continue to grow and we're going to continue to grow for multiple years. And so the percent of our Delaware oil tied to this contract is going to decline over time based upon the growth that we have of Delaware and we have a relatively flat commitment with this firm sales agreement.
So as we think about it, the incremental volumes there that we would have outside of this agreement are projected to be sold in the Midland basis, at the Midland market as we look forward, especially in those years 2020 through 2023.
Paul Grigel - Macquarie Capital (USA), Inc.
Okay, that's helpful. And then I guess changing to gas there.
If you guys end up in a circumstance where there's severe constraints or you can get it directionally towards Waha but there's no market for offtake, what are the options that exist in such a circumstance there?
Lance A. Lauck - PDC Energy, Inc.
Well from our perspective on takeaway for gas, Paul, really where we are today is we do really believe we're going to find those markets to get our gas to the various sales points, and we base it on the fact that we're talking to some very large companies that have the ability to ensure that that gas flows. So from our perspective, we feel good that we're positioned well for our gas to go to market based upon our development plans and how that stacks up with the basin.
Paul Grigel - Macquarie Capital (USA), Inc.
Okay. Thanks a lot.
Lance A. Lauck - PDC Energy, Inc.
Thanks, Paul.
Operator
Our next question comes from Kevin MacCurdy with Heikkinen Energy.
Kevin Moreland MacCurdy - Heikkinen Energy Advisors LLC
Morning. Thank you, guys, for squeezing me in.
Other operators have mentioned third party DJ maintenance in the second quarter. Are you guys expecting any of that?
And given your answer to that, what should we expect for 2Q and 3Q DJ growth?
Scott J. Reasoner - PDC Energy, Inc.
I think you've got a consistent – the spring and fall tend to be where more of the maintenance occurs. And when you start constructing a plant, you obviously have some connection work that has to be done.
So some of those facilities are taken down and put back up periodically to allow for the connection of those new facilities to be added. So is it going to be out of the ordinary?
I wouldn't say that but we're expecting at least the ordinary level of maintenance in there. When you start to speak to what's going to happen to DJ production over the various quarters, we don't give that precise numbers out there.
But just a little bit of direction maybe I can provide you, the thing about the DCP side of our production is second quarter expecting that to be up just a little because the freezes should be substantially less with the weather warming up here although we've got rain today and it feels like winter almost. And then secondarily, as Lance described, we do have 25%, 30% of our production goes on to Aka, and we have some room there and we've got a major pad, a 10-mile pad, I believe it is.
It's going to be connected to that and put on that system through the second quarter. So second quarter volumes up a little bit in the Wattenberg with the Delaware adding to that for the company.
And then third quarter, obviously depending on when that plant gets up and running, growth there as well; much of that associated now with DCP. And so we've got those different pieces playing into it and obviously a fairly dynamic set of circumstances there when you look at the overall picture.
Kevin Moreland MacCurdy - Heikkinen Energy Advisors LLC
Great, guys. That's very helpful.
Thanks.
Lance A. Lauck - PDC Energy, Inc.
Yeah.
Operator
Our next question comes from Michael McAllister with MUFG Securities.
Michael McAllister - MUFG Securities America, Inc.
Good morning, guys. Can you guys help me out with what your thinking is with all this work being done on the marketing end, where you guys stand for, like, 2019-2020 and your approach to hedging?
The hedge book might be different than what we've seen in the past because of all this work done.
R. Scott Meyers - PDC Energy, Inc.
From a hedging perspective, I mean, obviously with our leverage coming down, looking at our future, we use our hedges kind of as a protection against a turn to really commodity prices. So I think you could expect with where we're at right now for the leverage ratio, we might not have as much of our future production hedged right now as we have in the past but they'll still absolutely be part of the mix in the future.
We really want to be able to manage, if there is a correction, take time to manage those costs down, give the time for some of the service cost providers to make adjustments so that we don't have to have a significant turn to our businesses as a company that would not be hedged. So that's a little bit when we look to the future.
We have started looking at it and we do have about 35% of our oil hedged in 2019. We are starting to look at 2020 because of our economics, as you can see, it's $55.
It's still very strong with the rates of returns that we have. So we're going to continue layering that in and look for opportunities that we think that we can add some hedges that not only protect us but protect some of the value and the IRRs on our wells and our development.
Michael McAllister - MUFG Securities America, Inc.
Okay, that's helpful. And to think of it as being like you would go to the way you kind of approach it still is to kind of look for that protection of that 60%-plus, 60%, 70% per year.
This is always depending on where things are at certain times. But higher than 50%, let's say, is where you kind of feel – I'm just trying to get a sense of what you guys are willing to, for lack of a better way of describing it, risk to the upside.
R. Scott Meyers - PDC Energy, Inc.
I would say traditionally when we were 12 months out, we're more of a 70% kind of hedged company especially with the leverage ratio we have. That number is definitely coming down as we have some size and scale.
If I look 12 to 18 months out, 40% to 60% could be a range. It's definitely a tick down, again with our leverage ratio being at 1.3 times exit rate for this year and a 1.0 times exit rate for next year.
I think we're going to start managing as the quarters come go down. Now if there is something that changes our balance sheet structure, something like that, we would then consider increasing the hedges to protect the cash flow.
But I would definitely look for our hedged production to be a lower percentage than it has been in the future and probably 15% or maybe even a little sub of that.
Michael McAllister - MUFG Securities America, Inc.
That's very helpful. Thank you.
Operator
Our next question comes from John Nelson with Goldman Sachs.
Barton R. Brookman - PDC Energy, Inc.
Hey, John.
John Nelson - Goldman Sachs & Co. LLC
Hi. Thanks for squeezing me back in.
Just one true-up. The oil gathering system on Block 4, could you just remind us is that coming on when the Grizzly pad comes on in July, August, and then what will be the initial throughput capacity overall for that system?
Scott J. Reasoner - PDC Energy, Inc.
I don't have an accurate number for the throughput, John. I'd have to get more information from our engineering team to give you real numbers on that.
As far as the oil gathering system, it's coming on in pieces. We've got a section of it that'll be on here in the next couple of weeks, and that'll connect some wells that we've just recently drilled out there and completed.
At the same time, the main pipe through the system which is scheduled for the fourth quarter does not have an impact on the Grizzly. The Grizzly wells that are online are already connected to pipes.
So it's just that pipe through the middle of the system gives us more flexibility as we add more wells and also the idea that we can move at different directions as needed to take that oil away.
Barton R. Brookman - PDC Energy, Inc.
But John, I do believe our midstream group has engineered the system to handle the long-term forecast for our Block 4 development.
Scott J. Reasoner - PDC Energy, Inc.
Yes.
Barton R. Brookman - PDC Energy, Inc.
I don't know what that exact number is as far as the rated capacity. Some of that probably – the terminals that will be connected to the sales points obviously will have a short-term capacity and then they can easily be expanded.
Scott J. Reasoner - PDC Energy, Inc.
There is a long-term model. Bart's correct.
Barton R. Brookman - PDC Energy, Inc.
Yeah.
John Nelson - Goldman Sachs & Co. LLC
Okay. Thanks.
Congrats again.
Operator
And I'm not showing any further questions at this time. I'd like to turn the call to Bart Brookman.
Barton R. Brookman - PDC Energy, Inc.
Thank you, Kevin, and thank you, everyone, for your time today and just overall your ongoing support of the company.
Operator
Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.