PDC Energy Inc (PDCE) 2017 Q1 法說會逐字稿

Greetings, and welcome to the PDC Energy 2017 First Quarter Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Mr. Michael Edwards, Senior Director of Investor Relations. Mr. Edwards, you may begin.

Thank you. Good morning, everyone, and welcome. On the call this morning, we have Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; Scott Reasoner, Chief Operating Officer; and David Honeyfield, Senior Vice President and CFO.

We've posted a slide presentation that accompanies our remarks today on the Investor Relations page of our website, pdce.com. I'd like to call your attention to our forward-looking statements on Slide 2 of that presentation.

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

We held an Analyst Day 2 weeks ago on April 20, with an 84-page presentation. Those slides, as well as the replay, are available on our website. Today's slides include some of the same data as our Analyst Day slides, however, we do not plan on covering them in the same detail.

With that, let's get started, and I'll turn the call over to Bart Brookman, our CEO. Bart?

Thank you, Mike. Good morning, everyone. We begin 2017 with a very strong first quarter, and the company is well positioned as we move through the balance of the year. For the quarter, our production in both Wattenberg and Delaware exceeded our expectations, and we are particularly encouraged with the initial rates on the Wattenberg turn-in-lines so far this year.

The capital spend for the quarter was approximately $200 million, and we have line of sight towards the $750 million to $775 million range for our total 2017 capital spend. The company's operating costs continued to beat the expectations on a per BOE basis and for the remainder of 2017 expects strong reliable growth from our Wattenberg assets and encouraging new data from the Delaware Basin as we unlock this tremendous resource potential.

Let me cover some highlights for the first quarter. Production was 6.6 million barrels of oil equivalent, that is a 46% improvement from the first quarter of 2016.

87% of the production was from the Wattenberg field. And for the quarter, the company turned-in-line 43 horizontal wells, 29 of these in March. We anticipate this will result in an extremely strong second quarter, and I am proud we executed this without a single significant environmental or safety incident.

The lifting cost for the quarter continued to beat expectations, coming in at $2.98 per barrel of oil equivalent. That was an 11% improvement from prior year levels.

In total, oil deducts, including transportation, continued to show improvement, came in at $4.45 per barrel, again, that is an all-in deduct back to the well head.

Then from a financial perspective. We ended the quarter with liquidity over $940 million, capital spend came in slightly lower than expectation at approximately $200 million. Adjusted cash flow for the quarter was $114 million. And last, we are extremely pleased with the overall cost structure of the company on a per BOE basis, and David will cover this in a lot more detail in a moment.

Now what to expect for the balance of 2017? As we noted at Analyst Day, production is targeting the top 1/3 of our guidance range of a 32 million to 33 million barrels of oil equivalent. You should expect steady, stairstep production growth quarter-by-quarter as we go through the balance of the year, resulting in an anticipated exit rate of over 100,000 barrels of oil equivalent per day. Our pursuit of technical innovations and continuous improvements in our operations is ongoing, both in Wattenberg and the Delaware Basin. Expect a 3-rig pace in Delaware as we go through the year and a 4-rig pace in Wattenberg.

And again, capital spend should target the top half of our guidance range. We are now 1 month into the second quarter and are very encouraged by the production levels for the company and given its line of sight and confidence in a very strong second quarter and second half of 2017. I would like to thank again, as Mike noted, many of you for your attendance at the recent Analyst Day event in New York. Hopefully, we provided clarity around our ongoing development plans and the long-term opportunities that exist for the company.

Last, I know some of you may have questions regarding the tragic incident at Firestone, Colorado and the preliminary investigation results, which focused on a legacy vertical well and associated flow lines of another operator.

Let me first say that all the thoughts of us at the PDC go out to those affected by this tragedy. As you may be aware, the governor and the Colorado Oil and Gas Conservation Commission issued a notice to operators to inspect and ensure the integrity of existing flow lines within 1,000-foot of a building unit. I am confident in the overall integrity of the company's facilities and our operations because of our existing flow line integrity program. And PDC has an initial plan in place and is already taking action to comply with this notice and its time lines. We feel this compliance will have minimal impact on our production. Safety remains our highest priority.

With that, I'd like to turn the call over to Scott Reasoner for an update on our operations and what we consider a terrific first quarter.

Thanks, Bart, and good morning, everyone. We're very happy with the first quarter from an operational point-of-view. As you can see here, production for the quarter was just under 74,000 barrels of oil equivalent per day. This represents approximately 45% production growth from the first quarter of last year and 4% growth sequentially.

On the left-hand side of the slide, you can see that we had 43 turn-in-lines in the fourth-- or in the first quarter, and I'll point out that 29 of those were in March, which, as Bart indicated, have set us up for a strong start to the second quarter.

Lastly, on the right-hand side of this slide, you can see the breakdown of our 36 spuds for the quarter, 29 in Wattenberg and 7 in the Delaware.

Slide 7 gives a bit more color on a quarterly production and LOE. As I just mentioned, quarterly production increased by approximately 4% from the fourth quarter of 2016. Production came in ahead of our internal expectations, and we anticipate a pretty steady quarterly growth profile through the remainder of the year. We have 2 pads of recently turned-in-line SRL wells that utilize our new completion design of 170 feet between stages, and we are testing a 140-foot stage spacing as well as our new flowback techniques. This is similar to what we used as the basis for the increases to the XRL and MRL type curves announced at the Analyst Day. These pads, the [Schaumburg] and [Chesnuts], are the first SRLs to be completed with this method, and we are encouraged by the early results.

I'll point out that our LOE per BOE continues to benefit from the leverage of our increased production and overall cost management. We expect this to continue to improve as our production increases throughout the year. Great work all around from the operations team this quarter.

Just a few things to go over on Slide 8. First, our capital investment for the quarter totaled $200 million, with approximately 2/3 of these coming from the Wattenberg. From an activity standpoint, we have just added our fourth Wattenberg rig. You will also see that we have an overlap of a fourth rig in the Delaware through about September as the contract rolls off later this year. At which point, our plan is to run 3 rigs through the end of 2017.

On the right-hand side, you can see our anticipated cost structure for both basins. In the Delaware, I'll note that we've had some early start-up costs as we've gotten up to speed but are confident in the cost structure shown as we dial in our performance.

I'll spend a minute on Slide 9 as much of this was covered a few weeks ago at Analyst Day. As a reminder, the graph you see here is of our Kersey area. This area is approximately 30,000 Middle Core acres that is planned as our primary focus for the next several years. Shown on the top left of the slide are our current type curves. Our upgraded MRL and XRL type curves now stand at 800,000 barrels of oil equivalent and 1.1 million barrels of oil equivalent, respectively. You can see the spud and turn-in-line count by lateral length. Not shown here are the SRL pads that I mentioned earlier. We like what we are seeing from these wells, but with limited production data, it is a bit early to present the results so we will be sure to update accordingly in our coming presentations.

We've shown the LDS and Connie projects several times now. At this point, these wells and all of our XRL and MRL wells will be compared to our updated type curve profiles.

On Slide 10, you can see the basis for the new type curves and how we expect these projects to perform economically. On the top of the slide, you can see our SRL, MRL and XRL curves in the black lines of each graph. The blue lines represent wells with our new completion design, while the gray wells -- or gray lines are wells with the 2016 design.

Economically, our Wattenberg projects are expected to deliver estimated rates of return greater than 100% with extremely competitive F&D costs.

Moving to Slide 11, we have a summary of our Delaware operations for the first quarter. We have 7 spuds and 3 turn-in-lines, averaging 98% working interest.

In our Eastern area, we are very encouraged by the early production from our 10,000-foot Kenosha well. This is the first XRL for this area, and while it hasn't reached peak production, it's currently averaging approximately 2,100 barrels of oil equivalent per day of which, over 50% is oil, and this volume is a 2-phase production volume.

In the Central area, we completed the compression upgrade to our Westeros system that has restricted our Central area production, particularly our new Liam well. We recently turned-in-line 2 Greenwich wells. On one of the wells, we completed the full lateral and the other, we had mechanical issues that shortened the completed length. As we present the information, we will attempt to normalize our results to demonstrate the underlying development potential in the field.

Finally, in the Western area, one of the two wells that was planned for drilling and completion in 2017 is currently on flowback, while the other is being completed as we speak. These 2 wells not only represent all of our 2017 activity, but when combined with existing wells in the Western area, hold the entire acreage block through 2018.

On Slide 12, you can see the details of the Kenosha, Liam and HSS state wells in our Eastern and Central areas. These are the same graphs we showed a couple of weeks ago at Analyst Day. However, with the addition of rigs in February and April, we are excited to have multiple new data points coming in the next few months. As a reminder, we have 20 additional turn-in-lines planned for the remainder of the year.

Similar to the Wattenberg, we showed the economic profile of our Delaware projects on Slide 13. These economics are shown with our expected development cost structure, which excludes the pilot holes and assumes efficiency gains associated with pad drilling. Of note, as we continue to again confidence in our land requirements, we have scheduled a 6-well pad on the drill schedule for the fourth quarter that will test well spacing of 12 wells per section in the Wolfcamp A in our Eastern area. We are confident that in time, we will be able to improve on all these metrics. As it currently stands, these projects all provide great value.

In conclusion, we are very happy with our first quarter and think we are set up extremely well for the rest of the year. We look to continue building on our Wattenberg success, while the integration of our expertise into the Delaware is beginning to show.

With that, I'll turn the call over to David for a financial overview. David?

Thanks, Scott. So switching over to Slide 16. This takes a look at our GAAP results for the first quarter of 2017 and '16, and I'll add a little bit more color to Barton's and Scott's comments.

The quarter-over-quarter comparative production results reflect the 46% increase in 2017 production to 6.6 million barrels of oil equivalent. With the combined increases in production and realized prices, our total sales more than doubled to $190 million in the first quarter of 2017.

Net income for the quarter was approximately $46 million or $0.70 per diluted share compared to a net loss of $72 million in the first quarter of 2016.

Lastly, our net cash flow from operating activities, which is highlighted on the bar chart on the right, increased 38% between periods to $140 million with our production and price realizations being the drivers for this performance.

Slide 17 goes into a bit more detail in terms of our production cost, both in total dollars and per BOE. Just to remind everyone, when we talk about production cost and operating margins, we are including lease operating costs, production taxes and our transportation, gathering and processing, or TGP expense.

You can see that the increased production is paying for itself. By this, I mean that our increases in total LOE and TGP dollars are offset by our production growth, therefore the per BOE metrics for each of these items improved when comparing the first quarter results from 2016 to 2017.

With our continued increase in production, this is a trend we look to continue throughout the year. You'll notice that our production tax rate and expense increase from the first quarter of 2016, having an impact to both our total production cost and production cost per BOE. We really don't get too bothered by an increase in production taxes as it generally aligns with higher sales revenues.

The result of all of this is another quarter with strong operating margin coming in at approximately 80% for the quarter.

Moving to our non-GAAP metrics shown on Slide 18. The graphs highlight the adjusted EBITDAX and adjusted cash flow from operations. A quick clarifying note. We've recently modified the way in which we calculate our metrics in order to present adjusted EBITDAX. Previously, we just presented adjusted EBITDA. In looking at several of our peers, we believe this is a more comparable presentation format.

As Mike mentioned, the reconciliation can be found in the Appendix to this presentation.

To quickly summarize, we now include stock based compensation and we have added back exploration and G&G costs. All the comparative information related to these non-GAAP metrics for adjusted EBITDAX is now presented on this basis.

Adjusted cash flow from operations increased 25% in the first quarter of 2017 to $113.7 million compared to $91 million in the similar 2016 period.

The main drivers in the improvements quarter-to-quarter are not only improved commodity prices but our continued increases to production combined with cost management.

One item to call out specifically, and that you might recall from last year, was the impairment entry we recorded in the first quarter of 2016 for the notes receivable. This item is reflected in the cross hatch area on the adjusted EBITDAX graph.

In late April, just last week, we were able to negotiate and sell this note to a third party. As such, we will be recording income of $40.3 million in the second quarter of 2017 as a reversal of the previous impairment to reflect the cash proceeds received from the sale. In thinking about our expectations for cash and liquidity, the inclusion of the cash receipts from this sale will increase our total cash balance at the end of 2017 to be more in the range of $100 million to $150 million with our leverage ratio remaining at an estimated 1.7x. Please remember that our leverage covenant does not take into account cash on our balance sheet.

Turning to Slide 19, just a couple of quick comments about the balance sheet. The balance sheet remains very strong, with $946 million of liquidity as of the end of March 2017 with our leverage ratio coming in at 2.0x. This metric is presented based on the definition in our revolving credit facility consistent with the presentation in the 10-Q and our 2016 10-K.

Of note, and something folks will want to pick up in their modeling is that some of our cash now sits in short-term investments on the balance sheet. This amount was approximately $50 million as of March 31.

We combined the short-term investments with our cash balance and the availability under our RBL facility in presenting our total liquidity.

Moving to Slide 20. Here's a snapshot of our hedge position. There are no changes to the positions from what we showed at Analyst Day aside from some incremental CIG basis swaps, which are depicted at the bottom of the slide. For the remainder of 2017, we have over 7 million barrels of oil hedged at a weighted average floor price of $50 per barrel and over 36 million MMBtu of natural gas hedged at just under $3.50 per MMBtu.

As you can see, we also have a nice head start on our 2018 positions, and we will continue to methodically layer on new hedges as we deem appropriate and as we deploy capital.

Last item of note, while not a hedge per se, I wanted to call out that we have recently entered into a firm transportation agreement for natural gas in the Delaware for 40 million BTU a day through 2020 providing flow assurance and access to the Waha Hub. This is something that our midstream team had mentioned would be part of our execution plan in the Delaware to ensure flow of our products. We look at this as a prudent way to help offset some of the pressures that likely will be in the Delaware Basin through 2018 and gives good confidence around the sale of our products.

Closing out the slides, I'll quickly touch on our 2017 financial guidance. All of these metrics are the same as shown at our Analyst Day presentation. As Bart mentioned earlier, we expect our production for the year to be in the top 1/3 of our range of 30 million to 33 million BOE.

Our capital investments will also be in the top half of our range of $725 million to $775 million.

Our LOE, TG&P and G&A per barrel of oil equivalent ranges are presented in the bar charts. The LOE and TG&P per BOE metrics are slightly improved from our last earnings call from February.

Of note, I'd also like to call out the exploration in GMG expense line items of $5 million to $10 million for the year. These items get treated as expense for accounting purposes. As we highlighted at Analyst Day, we are investing in a number of pilot holes and seismic in the Delaware to accelerate our learnings and development confidence.

We hope all this information presented by Bart, Scott and myself on the call today has been helpful in terms of understanding the progress we're making in the Delaware and the performance in the Wattenberg.

With that, we'd like to open the lines for Q&A to the team.

(Operator Instructions) Our first question comes from Neal Dingmann with SunTrust.

Nice update on the heels of Analyst Day. Bart, just a quick question. I think you outlaid this, but I just want to make sure I'm clear on the -- as that third rig comes on the Delaware. Can you just talk about the focus region-wise for the 3 rigs for the remainder of the year and into '18?

Yes, I can cover that, Neal. This is Scott. We have a total of 23 wells -- I'm sorry, for spuds, we have 31 wells for the year, and the bulk of those are going to be in the Eastern area. And with that, I'll jump to our -- about 22 of those of the 29 -- 30 -- I guess 31 -- 22 of those are going to be in the Eastern area where we have the most knowledge, the most understanding of the economics and absolutely have the highest economic return there. So that's where we're headed with that rig. And right now, all 4 rigs are running in that one area.

And then, Scott, just one last follow-up in that area, the only other question I had was just on -- you hear a lot about on sand and just services in general. You guys aren't quite -- aren't quite at the size yet, but as you grow in the basin in the Del, would you think about contract in the Sand differently? Or would you kind of stay the course that you've always done?

Really, we tend to stay the course even in the Wattenberg where we've been running consistently, Neal. We really rely, I think it's a good move because we're aren't of a size yet where we can make a swing at big contracts for sand and chemical, that kind of thing. So we really rely on the service companies that we're using to do that. And I think that is, as you pointed to, that's probably the best way for us to do that at this point.

Our next question comes from Mike Scialla with Stifel.

Bart, you mentioned in your prepared remarks about the Firestone tragedy. I just want to see if your plan on doing anything else, other than following the Governor's directive of inspecting flow lines at this point. Any other changes to your operations in the basin?

This is Scott, Mike. At this point, we have a solid plan in place to follow the Governor's direction, and we're already well into that plan, executing around that. We feel like there's not any reason we can't get that done. There's really not a lot of other effort that needs to go into that in our mind. In terms of additional work, it's a substantial amount of work. But like I said, we've got about 100 guys up there already working on this. And so we really don't see it as being something that we can't get done. When you start to talk about it, it really parallels up well although there's a little bit more activity required over what has been our long-term plan of our flow line integrity management plan. It's something that has some slight nuances to it, but it's something that we can execute around very effectively. And I think we really are just accelerating -- some parts of that are just accelerating our flow line management plan.

Scott, also I want to ask you about the Greenwich pad you mentioned in your prepared remarks. You said you had some mechanical issues there. Just want to investigate that. Is that, you think, a one-off issue? Or any indication of the more complex geology in that region? Any commentary you can add around that?

And I appreciate that question, Mike. It's something that we really have -- what happened is we got a perk on stock and put some wire on top of it. We went into fish on that and it became a project that we couldn't win with, and so we cut it short. We had fracked 10 stages at that point, had nothing to do with the geology, the failure of the perforating didn't. So it really comes down to one of those one-off circumstances. We've been executing cleanly since that time. This was just one that didn't go the way we wanted it to, so really shouldn't see that often. I hope never again, but you can never say that.

Our next question comes from David Tameron with Wells Fargo.

Just a quick question on the -- Scott, if you could just go back to the older Colorado issue, if you will. Is there a thought -- some of these old vertical wells when you start looking at whether it's to replace the flow lines or just manage an integrity and you read some of the regs, it seems like it always make sense to shut in some these vertical wells just to protect yourself against any future liability or anything along those lines. How do you guys think about that option?

Yes, and I want to start that with -- as Bart described, safety is always our top priority. And then we take into consideration all of those things, David, that you brought up when we decide how we're going to operate our wells. That flow line integrity management plan that we've had in place for several years now is something that we've leaned on. We have tremendous amount of testing goes on every year. And so really we don't see that particular circumstance that happened, the issue that came up in Firestone as being a typical circumstance. And I think it was described very well by the fire department that it's definitely not something we should see repeating.

Okay. So just no -- but just as far as you look at some of those vertical wells, does it make sense to keep some of those running?

It's one of those things, David, where we keep them producing. They're about 10% of our production. We're constantly looking at them and making those decisions as time passes. We plug wells every year and plug a significant number and continue operating the ones that we feel like warrant the additional capital expense to maintain any of these issues that we come up with. And they're really infrequent, again, based on this testing plan. We have a good handle on, I think, on the full line integrity. And as Bart described, we're confident in the reliability of our facilities and the flow lines that are out there.

Okay. And then just let ask me ask you an impossible question along those same lines, see if you'll -- see what you can give me, if anything. If I think about just the regulatory environment going forward, how do you guys view this as, and even if it is viewed as a one-off incident, how do you view this as your ability to get any future permits you need? And how do you view this as -- any impact on what this looks like going forward? Anything you can give us along those lines?

Yes, David, this is Bart. That will be pure speculation on our part to try to anticipate how it impacts permitting or any of the other forces in the States. So I think we're going to have to stand back on that one. And there's still tax being gathered in those 2.

Our next question comes from Geoff Jacques from Iberia Capital Partners.

So for the SRL well that you guys are bringing online this year, are all those going to be on the updated design? Or are there some legacy wells that maybe timing didn't get ahead and pushed out to 2017 and they are on the old design? Or is it -- are all of them going to be on the new design?

The wells that we turned in-line this year are going to be on the new design. They're at the 170 foot between stages in terms of the lengths of those stages there. So we're on that plan, and we've actually -- in one of the 2 batteries, and I can't -- I am not sure if I remember exactly which one of these, but we've actually gone down to 140 feet on those. And we're also, the team, I believe, not 100% there yet, but I believe we're going to be executing on some 100-foot stage spacing like what we see on some on those 140-footers from last year. And so continuing that effort going down towards shorter spacing, don't know how that all play out...

(Operator Instructions) Our next question comes from Mike Scialla with Stifel.

Just want to follow up. David, you mentioned -- I missed part of your comments, I apologize, on hedging. You were talking about the Delaware, in particular, pricing there. What have you done there to -- I think you had mentioned about mitigating risks on some of your products there?

Yes, Mike, what I was describing specific to the Delaware was that in addition to hedging, we've actually placed or we've actually purchased some firm transport out of the basin, and that's 40 million a day. It takes us into the Waha Hub. So while not a hedge, it provides us flow assurance. So that's something that we think is really important. When we think about our general hedging program, we tend to look at our total production, including the Wattenberg, and we're always looking at basis in those sorts of things. Right now, obviously, on the gas side, CIG is probably our dominant basis position, so that's what we're taking the closest look at. So hopefully that helps.

Yes, it does. And then -- sorry, I assume what you are referring to your financial situation, obviously. On your crude in the Delaware, any concern or any -- seeing any deducts for gravity and any thoughts on trying to mitigate that risk going forward?

Mike. This is Lance. From API gravity standpoint, we're not seeing any incremental deducts for the variability in API across our position there. There is a slight higher transportation charge per barrels on the West side versus the East side. But from all that we see here in front of us today, there is no incremental deducts for API differences.

And Lance, can you tell me what kind of gravity difference you see across your acreage from East to West?

Sure. So in the Eastern side, we're averaging right in that mid-40s API range. As you go towards the Central area, where more sort of the lower 50s to maybe the mid-50s. And then on the Western side, we're more than mid-50s to maybe a little bit higher than the mid-50s, but sort in that type of range.

Got it. And then those Western wells, the process of completing, can you say how long those laterals are?

Yes, both wells, Mike, are 7,500 footers. We originally planned to have 10,000 footers, but we landed at 7,500. And the first one is completed and in flowback and the second one is currently being fracked.

Okay. And any drilling issues there that prevented you from going to the 10,000-foot level and do you plan when you drill additional wells over there to target 10,000 feet?

No. We're planning to target 10,000 feet. And really, what came up was we had some loss circulation issues. I've seen these kinds of things in other basins, and we've been able to manage them very effectively. We decided not to chase that project because it can get expensive when we hadn't prepared for it, so we decided to cut it short at 7,500 foot. I think a great move on our team's part to do that. And if we can see what those produce at 7,500-foot, we'll understand better what the economics look like et cetera out there. But in the future, we'll be looking at 10,000 feet. And I think if we prepare in advance, and there's number of different things our drilling team is doing out there to get ready for that. But I think we're going to be able to manage that circumstance very effectively.

Okay. And then Scott, you had mentioned that you're doing a 12 well per section test in the Wolfcamp A. have you seen offset operators test that kind of density? And is that going to include more than one landing zone within the hub? Maybe just a little more commentary on that? And then also two, is that spacing built into your 785 net well drilling inventory?

Mike, I'm going to start and then I think Lance is going to jump in. He's much more familiar with what's going on in the offsets. In terms of the plan, we plan to stay in the Upper A -- I'm sorry, in the A and do a -- I'm sorry in the A and do an Upper A, Lower A Chevron across there for 6 wells. That would equate to 12 wells per section. And so we're going to get a good test in what that means in the A as what the plans are at this point. And I'm going to pass it over to Lance and let him answer the rest of that.

So Mike, with that test of 12 wells per section in the A that Scott described, that compares to our acquisition analysis, our inventory of 8 wells per section in the A. So based upon success of that, would then have upward pressure on our inventory, which should be a positive thing for the company. As far as other companies test in that tight of spacing, I know that, for example, Cimarex has talked about various tighter down spacings that they are doing. In fact, I'd probably start maybe more on the Western side where they have tested 6 and 8 wells per section in the Upper Wolfcamp in Culberson County and they now plan to do a 12 well per section test in Culberson County called their Seattle Slew test there. They're also testing tighter spacing. This is Cimarex in Reeves County also in a test called the Wood State. So that's another downspacing that they're looking at. And then I'd say for the central area, the one we probably look at that's testing this most right now would be Resolute. They've got some work that they're doing on various downspacing tests there between the Wolfcamp A itself as well as Wolfcamp A and the Wolfcamp B. So there's 2 real examples that are pretty close offsetting this that are testing this tight of spacing. So as industry progresses forward, as we get more data, we look to see a lot of additional of testing of this downspacing in offset locations and also as well as ourselves. So hopefully, that gives you some insight of what we're looking at.

That's great. Where is the -- real estate focus primarily on the A for this year, any thoughts on testing other zones?

For this year, I'll share some thoughts and turn to Scott. For this year, a lot of our work is focused on HBP and our acreage, and with that, we're doing primarily the Wolfcamp A and the Wolfcamp B intervals out there. As we continue the HBP, the locations and then get more line of sight on then looking at how we continue to build and grow out the inventory. Clearly, we're going to be looking at additional testing and other intervals, both below that and above that, the A and the B that we have talked about. So it's something that's on our radar screen. That's probably more a year or 2 out that we'll start looking at some of the testing of the other intervals. But keep in mind too there's a lot going on in the industry test and additional intervals as well, so we continue to watch them us we're looking at our own programs as well.

Our next question comes from Michael Hall with Heikkinen Energy.

Michael Hall of Heikkinen. I guess, just quick one on G&A, it came down nicely kind of quarter-on-quarter relative to the back half of last year on a dollar basis. Just kind of curious what drove that. And any commentary on whether that sort of dollar level can be held going forward?

Michael, this is David Honeyfield. So our guidance range right now is $3.25 to $3.60 per BOE for the full year, so we continue to -- as you know, we're adding a lot of folks this year, but the good part is, is we continue to see that trend down. So I think that the trend is something that we anticipate for the full year. Nothing else really remarkable in there.

Okay. So not on a per BOE basis, but on just the straight absolute dollar basis. The quarter-on-quarter decline is just kind of relate to the year-end expenses...

Probably just kind of make sure that we trued up for bonuses last year and then we had some deal costs that were in there. I think we had just about $11 million of deal costs. Is that right?

Yes.

So that was probably the biggest difference quarter-to-quarter.

Okay. I guess, maybe one more, quick one just to follow-up on the firm to Waha. Just to be clear, so that gets you Waha pricing? Is that...

Yes, that gets us transport to the Waha Hub. And then from there, you get access to the Mexico markets. You've got good flowback to the East and the shift channel markets and such. So yes, just gives us great flexibility.

Okay, based on the flow with the Waha price up in terms of your...

Yes, that part is -- that's the index that we're going to be trading against.

Got it. And then can you disclose what you paid for the tariff to get there?

Well, what we can say is that, that's on a FERC-regulated pipe, so it's a tariff rate. At this point, it's probably not something that we're going to put out there. What I will say is we've captured all the volumes and the commitments in our commitment tables that's in the 10-Q, at least in aggregate.

Our next question comes from Stark Remeny with RBC.

I actually just have one quick one and I do apologize for yet another one on Firestone. But as you guys think about the LOE and G&A trajectory through 2017, how do you see any specific impact as it relates to complying with the Governor's orders? And maybe just specifically as it relates to 2Q versus trending for the back half?

This is Scott, and I can answer that fairly briefly. Actually, we don't see a lot of impact on our LOE. It's really comes down to it's going to be a lot of hard work over the next 2 months for our teams. We may see a little bit of overtime, but it's really not going to influence the second quarter overall. And I really think we're set up with a good plan. And like I said, our guys are going to be executing over that -- around that over the next -- and we've already started that, but we'll be executing around that plan and should be based on the Governor's directive, we need to be done with that 60 days. So we feel like we can get that done.

Our next question comes from Michael Glick with JPMorgan.

Just to be clear on your guidance, it's based on your existing SRL types curves in the Wattenberg and your acquisition type curves in the Delaware, that's correct?

Yes, that is correct. The only ones we've upgraded are the XRL and MRL curves in the Wattenberg.

Got you. Okay. And then just Western Delaware real quick, can you talk about the completion design on those 2 wells?

Yes, I can give you a little bit of a flavor. We really haven't varied it too much from our standard design out there. We're pumping 2,000 pounds a foot in terms of sand. Have 50 to 60 barrels per foot of fluid. And we really run about 100 feet to 125 feet as between stage spacing, so really pretty typical of our completion design across the field. Where we haven't varied things much over there.

Our next question comes from Mike Scialla with Stifel.

Yes, just had a couple more. In DJ, one of your competitors talked about a new completion design basically using just higher fluid concentration and not more proppant. I wonder if that's anything you've considered just trying to stay with your sort of standard 1,100 pounds of sand and just increasing the fluid to see what that will do.

Mike, this is Scott again, and I am not familiar with the competitor that is out there talking it up. But I will tell you, we've tried a number of different approaches to this. Varied our gel loadings, our sand concentrations and rates. A whole lot of different things and continue to do that, and we continue to try to find those types of things. Definitely, we'll be interested in finding out who that is and we can get that but from some of our avenues through the service companies. But we haven't seen additional sand concentrations help, and we're continuing to test that, but that it's that type of thing that we learn from and continue to grow our reserves from. And I think if that pays dividends, obviously, we'll be taking a look at that in short order. But we've tried it in the past and it hasn't really made a big difference. Some of the variations we see out there may be a function of the GOR in the area, we're in that Kersey area typically this year, and many of our peers are operating in a little bit lower GOR areas. And some of those influences of higher sand concentrations frack, for an example, may be a function of moving more fluid through that rock.

Okay, got it. And then just one bigger picture question. If oil prices are to stay below $50 here, does that change the longer-term plan for you at all?

Mike, no. I think if we're in this -- $45 to $50 range our plan for the year is intact. Our permits -- we obviously have the Delaware where we've been very clear on our efforts to hold the acreage. Our Wattenberg, if you go back to what Lance presented at Analyst Day in some of the economics, even at $40 oil and $2.50 gas are incredibly strong in Wattenberg. So I think we've got a good path. I think we're not going to overreact to a market that corrects, hopefully, short term. If our internal outlooks shifted to where we saw a longer term price correction, I think that will be something where we'll start looking at '18 and '19 and where we take the company. But I think we've got a good plan this year, and you can expect us to grow in line with what we're guiding.

I am not showing any further questions at this time. I would like to turn the call back over to Mr. Brookman for closing comments.

Yes, thank you, Kevin, and thank you, everybody, and all the Mikes out there. And we appreciate the ongoing support and expect more to come as we go through the year.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.