PDC Energy Inc (PDCE) 2017 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy Fourth Quarter and Year-End Conference Call. (Operator Instructions) 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 of Investor Relations. You may begin, sir.

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 the slide presentation that accompanies our remarks today. We also filed our 10-K this morning. The press release and the presentation are available on the Investor Relations page of our website, which is pdce.com. I'd like to call your attention to our forward-looking statements on Slide 2 of that presentation. We will present some non-U. S. GAAP financial numbers today so I'd also like to call your attention to the appendix slides of that presentation where you'll find the reconciliation of those non-U. S. GAAP financial measures.

With that, we can get started and I'll turn the call over to Bart Brookman, our CEO.

Thank you, Mike, and welcome, everyone. 2017, a solid year of growth and ongoing operational execution. The company enters 2018 as strong as ever with 2 premier assets. We are extremely pleased with the exceptional talent we have assembled on our Wattenberg and Delaware teams and for 2018 expect tremendous financial strength to emerge as we continue with our value focused drilling programs and strong production growth. Let me hit some 2017 highlights. A 44% increase in production to 31.8 million barrels of oil equivalent. We exited the year at 97,000 barrels of oil equivalent per day and we're very pleased to increase our oil production 48% as we began to see the strong oil contribution from the Delaware Basin. We recently announced year-end 2017 proved reserves of 453 million barrels of oil equivalent, it's a 33% increase from the year-end '16 and a reserve replacement of approximately 450%.

In Wattenberg, 2 significant acreage swaps and one acquisition helped create our 3 focus areas; the Kersey, Plains and Prairie acreage blocks. These 3 areas are instrumental in providing an opportunity for 2-mile laterals and enhanced capital and operating efficiencies. In Delaware, we gained operating momentum throughout the year as we staffed our team and exited 2017 with strong production growth, improved drill times and line of sight to a tremendous resource potential. Scott and Lance will cover this in a lot more detail in a moment. Some key financial metrics for 2017. Lifting costs held under $3 per barrel of oil equivalent, liquidity at year-end was just under $900 million, year-end leverage ratio 1.9x, capital spend for the year ended up at $790 million and our net cash from operating activities improved 20%. Overall, we are very pleased with the financial condition of the company as we wrapped up 2017.

Now let me update everyone on 2018. Our capital spend range previously announced in December remains $850 million to $920 million. Production is expected to be between 38 million and 42 million barrels of oil equivalent. That implies approximately a 25% growth in our overall production on a Boe basis. However, we do anticipate crude oil volumes for the company to grow by approximately 35%. In Delaware, we expect strong and steady growth throughout the year. In Wattenberg, production growth should be modest in the first half of the year, but we anticipate it will ramp up considerably in the second half with planned DCP midstream expansions. Oil mix for the company should increase in range between 42% and 45%. And we have a slight increase in our expected spud count compared to our December announcement, primarily due to the Delaware drilling pace and Scott will cover this in a moment.

We expect lease operating expenses to remain under $3 per barrel of oil equivalent and our December exit rate should be approximately 130,000 barrels of oil equivalent per day. Our leverage ratio is expected to improve to 1.4x. Liquidity year-end should once again be strong as we expect to exit the year barely drawn on our revolving credit facility. And most importantly, with oil over $55 a barrel, the company should be cash flow positive for the second half of 2018. In closing, I would like to thank all the PDC employees for their efforts in 2017 and in particular our operations and EH&S teams for their ongoing focus on safety. The company's organizational strength when combined with our quality assets, value focused drilling programs position us for continued growth and financial success for many years to come.

With that, I'd like to turn this call over to Scott Reasoner. He will update you on the company's operations.

Thanks, Bart. Good morning, everyone. Let me first start by also thanking our teams. 2017 wasn't without challenges at times, but I'm very proud to say that we worked very well together throughout the year and carry tremendous momentum into 2018. Slide 7 gives an overview of some of the key operating statistics including our annual production and oil production increases of 40% plus. A few things to call out. Wattenberg production of just over 76,000 barrels of oil equivalent per day for the quarter is actually down a hair compared to the third quarter. As you can see, we had 19 turn-in-lines in the fourth quarter, which is down from 39 in the third quarter. To reiterate what I said on our third quarter call, we expect the Wattenberg to be challenged in terms of growth for the next couple of quarters due to midstream constrains, but believe we have fully captured that in our guidance.

Which brings us to the Delaware, which grew 25% quarter-over-quarter to over 16,000 barrels of oil equivalent per day. Obviously with the Wattenberg a little constrained, we expected Delaware to continue serving as the main growth engine for the company for the first 6 months of the year. Moving to Slide 8, we give a detailed capital breakdown for the year. As Bart mentioned, total capital for the year of approximately $790 million came in below our expectations thanks in part to a very efficient fourth quarter totaling just over $170 million. On the right hand side of the slide, you can see our spud and turn-in-line details for each asset as well as $37 million related to Delaware infrastructure. We plan to accelerate this a bit in 2018 as we continue to build value through oil and gas gathering and our water management assets. We provide a look into our quarterly production and LOE on Slide 9 with both trends moving in the right direction.

In terms of production, over 94,000 barrels of oil equivalent per day in the fourth quarter represents 35% growth compared to the fourth quarter of 2016. Digging in a little deeper and looking at our oil growth over the same time period, you can see it outpaced total production by a good bit growing 49% compared to the 35%. This obviously has a lot to do with the Delaware becoming a larger part of the portfolio. Considering it is also the more expensive operating basin, our LOE trend is even more impressive. While 2017 LOE per Boe did increase compared to 2016, 2016 had virtually no Delaware operations. So, we're very happy to come in below $3. Scott will give more color on our 2000 expectation -- our 2018 expectations, but we expect to maintain our current cost structure.

Moving to Wattenberg on Slide 10. There really isn't much new to cover at this point as we continue to wait on Plant 10 to alleviate some of the pressures we've been seeing for the better part of 9 months now. You see on the right just what we've been fighting. The average line pressure on DCP's gathering system are shown going back to 2015. The first dotted line shows the impact that DCP's Lucerne 2 plant had back in 2015 as the average line pressures decrease by approximately 100 pounds over the next few quarters. I'll caution you that a lot has changed since then in terms of operator activity and pad development so we don't necessarily expect the same drop with Plant 10, but we do expect to see some relief especially after some of the flush production behind pipe moves through.

It is important to note that with Plant 11 scheduled for the spring or summer of 2019 and discussions ongoing for Plant 12, we really feel confident that DCP is making the right kind of progress to put this issue behind us once and for all. Starting on Slide 11, I'd like to spend the next couple of minutes really highlighting some of the operational execution we've been able to accomplish in the Delaware. We've been able to consistently improve our drilling and completions for several quarters now, which clearly help shape the quarterly production profile shown here. Obviously it's easier to grow 100% plus off a new asset with a similar base, but at over 16,000 barrels of oil equivalent per day in the fourth quarter with expectations to more than double total production in 2018, we start to see a more and more significant wedge of relatively oily production coming online.

Speaking of 2018, we plan to spud and turn-in-line between 20 and -- 25 and 30 wells in our 2 focus areas of Block 4 in the eastern area and the North Central acreage of our Central area. In terms of specific improvements we've made in 2017, Slide 12 shows pretty clearly the increased drilling efficiencies throughout the year as well as the strong performance of our recent wells. Starting with the drilling pace, I'm sure many of you picked up on our increase in expected spuds for 2018 from our original budget, which is a direct result of what you see here. 3 things have really led to the 40% improvement we've captured throughout the year. Finding the proper fit-for-purpose rigs was the first step. We are very happy with the 3 rigs we're currently operating and feel that we get better and better each day. Second is more a product of time, but having consistent drilling crews has really paid off.

Finally, as we moved through the year and met some of our early lease obligation initiatives, we really began to focus on 2 key areas. Over time our geologic understanding has increased and we're experiencing fewer and fewer surprises. Most importantly, there's still plenty of room to improve as evidenced by our best well, which is over 50% faster than our current average pace. In terms of productivity per well, we're very happy with our recent performance and are excited to continue delivering impressive results throughout 2018. As you can see on the graph on the left hand side of the slide, our 30-day production results stack up very well with operators with much longer tenures in the basin. Important to note, we choke our wells back pretty aggressively and are actually -- and our wells actually improve relative to our peers when looking at longer production time periods.

In terms of cost per well, our expectations haven't changed from the time of our initial 2018 budget release in December. We expect total cost between $9 million and $14 million per well depending on lateral length and are hopeful that continued completion refinement and drill time improvements will offset any material increase on the service side, but for us to closely monitor our pace, capital spend and DUC inventory as we move through 2018. Moving to Slide 13, we take a closer look at our Eastern Area Block 4, a key focus area moving forward. As you've seen in the past, well results from this area have been very impressive leading us to increase our expectations for the area. Instead of normalizing production to 5,000 feet, this quarter we're showing the cumulative production of our 4 most recent XRL wells compared to XRL type curves of 2 million and 2.5 million barrels of oil equivalent EURs.

Generally speaking as it's still very early, our Wolfcamp A XRLs are tracking above the 2.5 million barrel oil equivalent curve while our Wolfcamp B wells are trending between the 2 million and 2.5 million barrel oil equivalent curves. As you can see, albeit through an early sample, all 4 wells are outperforming to date. Of note, these wells average more than 70% crude. In terms of 2018 activity, expect about 2/3 of our planned turn-in-lines to be focused in this area, including our Grizzly Bear pad which is testing 12 wells per section equivalent in the Wolfcamp A, a Grizzly West well testing in Wolfcamp C and the installation of a crude oil gathering system. Slide 14 takes a closer look at our other primary focus area, the North Central. Similar format as the previous slide with the map on the right hand side highlighting our planned activity in 2018, you can see by the location of the expected turn-in-lines that we're starting to cover a wide footprint of this acreage.

We've also updated production from 4 key wells in our North Central area with all 4 wells tracking well above the acquisition type curve. In 2018 we're off to a good start operationally with the 3-well Greenwich pad and Sunnyside well starting initial flowback as we speak. With approximately 10 turn-in-lines planned including a few multi-well pads, we see 2018 as a key time in unlocking some additional value that may not be fully captured right now. Last on Slide 15, a quick look at some of our 2017 accomplishments and 2018 initiatives. In 2017 I want to again thank the teams for their incredibly hard work throughout the year. We believe we've accomplished everything we set out to do this year and are excited to keep things moving in the right direction in 2018. In terms of our 2018 focus, we are really excited to analyze results from our Delaware downspacing tests later this year and hope to continue realizing efficiencies throughout our Delaware program as we focus in on 2 very prolific areas in our acreage.

With that, I'll turn the call over to Scott Meyers for a detailed look at our financials and 2018 guidance.

Thanks, Scott, and good morning. Before getting started, a reminder for more details on the materials presented this morning, we ask you to reference our press release issued last night and our 10-K filed this morning. On 17, I'll touch on a couple of the key metrics for the quarter and year before going into a quick overview of our current hedge and liquidity profile and giving more color on our 2018 financial guidance. Generally speaking, the fourth quarter was extremely smooth from an operational standpoint. Net income for the quarter was $78 million or $1.17 per share compared to a net loss of $56 million or $0.94 per share in the fourth quarter of '16. This number has a lot of noise with the impact of the federal tax changes, a large mark-to-market adjustment for our derivatives as well as the debt extinguishment costs. So, let's jump to oil and gas sales for a better look at the quarter.

Oil and gas sales, which increased from 2016's fourth quarter and full year to $277 million or 64% and $913 million or 84% respectively. This increase has driven our net cash flow from operating activities to $177 million for the fourth quarter, which represents a more than 40% growth compared to the fourth quarter of '16 and about a 20% growth sequentially. As previously mentioned, the fourth quarter was impacted by the tax legislation as our net deferred tax liabilities decreased by approximately $115 million for this item leading to an income tax benefit in the quarter. The graph to the right shows the quarterly trends of our net cash from operating activities as well as production by basin. On Slide 18, you can see similar growth trends in both our adjusted EBITDAX and adjusted cash flow from operations on a quarterly basis. Please keep in mind that a detailed reconciliation of all the non-GAAP metrics can be found in the appendix.

Adjusted cash flow of $175 million in the fourth quarter and $580 million for the full year represents approximately a 25% increase on comparable 2016 periods. The increase in adjusted cash flow was primarily due to increased production volumes and realized prices between the 2 periods. In terms of production costs on Slide 19, Bart and Scott have already touched on LOE; but as this is a highlight for the company, I'll give a bit more detail. Although at first glance there appears to be a slight uptick in the LOE per Boe compared to 2016, the breakdown by basin shows that our Wattenberg LOE per Boe actually decreased year-over-year. This is a testament to the great job our team has done managing cost throughout the year. Meanwhile you could see our lifting costs in the Delaware are higher than the Wattenberg, which is to be expected. Overall, our production costs have increased in line with sales while our change to TGP is primarily due to a contract change made in the second quarter of '17.

Our overall net margins improved in 2017 compared to 2016 so highlighting this TGP increase shown here is purely geographical. As you'll see in a minute, our TG&P per Boe is expected to change in 2018 due to the new revenue recognition standards we've adopted. Moving on to Slide 20. We give a look at our updated debt maturity schedule including our $600 million 5.75% senior note issued earlier this year. As you will see, we currently have an undrawn revolver with all of our debt maturities in 2021 or later. Our year-end 2017 liquidity pro forma for the January 5 closing of the Bayswater acquisition was approximately $700 million. Our year-end debt leverage ratio was 1.9x. We expect our 2018 activity to lead us to reduce our leverage ratio to 1.4x. Additionally, depending on the timing of payments and revenues received at the end of the year, we expect to exit 2018 minimally drawn on our revolver.

In terms of hedges, we have approximately 70% of our 2018 crude hedged at almost $52 a barrel and approximately 60% of our gas production at just under $3 per MMBTU. We've seen the basis differentials expand a bit recently and it's important to point out that we do have basis swaps in place for approximately 55% to 60% of this expected gas production at approximately $0.45 per MMBTU. I'll point out to you in the appendix for more details on those trades. Overall, very strong from a leverage and liquidity standpoint with continued improvements expected in 2018. Moving on to Slide 21, I'd like to spend some time going over our current guidance and a few notable changes from our previously released guidance back in December. First, production and capital. As Bart and Scott have already touched on, our production and capital ranges remain unchanged at 38 MMBOE to 42 MMBOE and $850 million to $920 million.

These ranges are obviously consistent with our pre-released ranges back in December despite a few changes, namely increase in Delaware activity and the timing of Wattenberg midstream expansions offset by curtailments and freeze-offs in the first half of '18 in Wattenberg. In our Delaware, our December budget included 22 spuds and turn-in-lines in the year with 27 completions. Essentially looking at our drill schedule, we've had a handful of spuds that we've been able to push forward thanks to the improvement in drill times that Scott provided earlier, which has led to a few additional turn-in-lines. However, for all intents and purposes, these turn-in-lines were essentially paid for in our prior budget and we're now able -- be able to add some late year production and our range of 25 spuds to 30 spuds and turn-in-lines is now the expectation for 2018.

This partially explains the improvement in our estimated December exit rate of 130,000 barrels a day equivalent from the 120,000 barrels a day equivalent in December as a result and also the result of our block 4 wells. With a production profile approximately 25% growth in '18 and more than 30% growth in 2019 as Lance will detail in a second, look for us to closely monitor our drill times projected capital as we move throughout the year placing an emphasis on returns and free cash flow generation. Our updated price realizations are 91% to 95% for crude, 55% to 60% for natural gas and 30% to 35% for NGLs. These realizations exclude TGP, but do include the impact of gas basis differentials increasing that we've experienced lately, as well as changes to the rev rec standards, which you'll see lowers our TGP per Boe below. Our projected per Boe cost metrics are shown trending in the right direction.

Obviously with Delaware and its higher lifting cost becoming a larger portion of the portfolio, we consider holding our overall LOE relatively flat a positive. Finally, the major difference from our December guidance and the one that drives tremendous value is the change in commodity mix expected this year. As you recall, the guidance indicated 42% crude oil. Now we anticipate crude oil to account for 42% to 45% of our total production. This is due to the increase in per well Delaware production results and should lead to positive impacts in our realized prices per Boe as well as margins. Finally, wrapping it up on Slide 22. I've highlighted a few key takeaways. First, our expected outspend for the year. Assuming an updated price deck of approximately $57.50 per barrel and gas around $3 per Mcf including the increased gas differentials that I alluded to earlier, we now expect our outspend to be less than $90 million for the year.

This includes considerations for cash flow outspend in the first half of the year and being cash flow positive in the second half of 2018. When including proceeds from the 2 recent transactions that Lance will touch on in a minute, our impact of the outspend moves closer to approximately $25 million for the year. This obviously shows the strength of our asset base and the returns we're able to generate. And again, look at our leverage ratio as it improves moving from 1.9x to 1.4x by the end of the year. We fully expect our 2018 to be a year highlighted by unlocking potentials and the creation of tremendous momentum that will carry us into and throughout 2019.

With that, I'll turn the call over to Lance for a closer look at our updated inventory and multi-year outlook.

Thanks, Scott. And in this last section of today's call, we're going to provide several updates including our 2017 year-end drilling inventory, status of multiple transactions and corporate outlook that we currently project will deliver material free cash flow in 2019. Let's begin with Slide 24. Earlier this month we announced our year-end 2017 proved reserves, let me provide some of the key highlights. First, our total proved reserves grew to about 453 million barrels of oil equivalent representing a 33% increase over last year. Additionally, we posted a very strong all-sources reserve replacement ratio of approximately 450% driven by strong reserve increases in both Wattenberg and Delaware. The largest component of the reserve increase came from our Delaware Basin assets, which grew to nearly 100 million barrels equivalent as of year-end 2017.

As Scott highlighted earlier, we are seeing several measured improvements in our Delaware Basin performance and our increase of approximately 65 million barrels of oil equivalent improved reserves demonstrates another step towards unlocking significant value from these assets. The table at the bottom of the slide shows our proved reserve walk from year-end 2016 including our net additions of approximately 143 million barrels of oil equivalent. Finally, our SEC b-tax PV10 value increased by over 90% to $3.2 billion as of year-end 2017 driven by the 33% increase in reserves and 20% increase in the average NYMEX price of both oil and gas. Slide 25 provides our year-end 2017 update to our Wattenberg drilling inventory. Both our 2017 trades and our bolt-on acquisition that closed in January of '18 continued to improve our capital efficiency by converting more of our inventory to mid and extended reach laterals.

One of the key takeaways is that we maintained our overall gross lateral footage of about 9.5 million lateral feet and that's after drilling 1 million lateral feet in 2017, but for a good portion of the year we utilized 4 rigs compared to the current 3 rig pace. Our average lateral links per well as of year-end '17 increased by nearly 20% to 6,300 feet per well compared to year-end '16, which demonstrates continued efficiencies our teams are delivering from our Wattenberg field. Our drilling program is currently focused in our Kersey area where we expect to deliver some of our highest economic returns in the field. The pie chart provides a breakout of our drilling locations into our 3 core positions of Kersey, Plains and Prairie. We continue to consider acreage trades with other companies to convert more of our inventory to longer laterals. Let me now bring everyone up to date on our Delaware Basin inventory and as you recall, our acquisition inventory was based on 1-mile laterals.

Today's presentation converts our inventory to 1.5-mile lateral equivalents, which more closely reflects our ongoing drilling program. So, let me start on the left portion of the waterfall graph. First of all, our original acquisition inventory footage of 4.1 million lateral feet converts to approximately 540 locations on a 1.5 mile equivalent basis. During '17 we drilled or impaired approximately 50 locations resulting in the year-end '17 inventory of about 490 locations or about 3.7 million lateral feet. We then identified 200 potential additional locations in our oilier focus areas based on our planned downspacing test and to make our spacing more consistent with the assumptions of our offset peer companies. This brings us to a total inventory of 690 locations currently in inventory representing about 5.2 million lateral feet. Of the 690 wells, 450 are in our primary oil focus areas as highlighted on the map.

This focused inventory of 450 wells provide our highest rates of return from an approximate 40% to 70% crude oil mix and EURs that range from 1.0 million to 2.6 million barrels of oil equivalent per well depending upon lateral length. The focused inventory of 450 1.5-mile equivalent laterals provides an estimated 15 to 18-year inventory based on the current drill pace. The balance of our inventory of approximately 240 locations typically have a higher GOR, contain more non-contiguous acreage or may require additional technical evaluation. We're developing initial plans to increase capital efficiency from these locations, including potential trades or consolidations. I want to remind everyone that we're still in the very early stages of defining our inventory in our Delaware Basin assets and that additional potential locations may exist in the Bone Spring, other Wolfcamp intervals or from further downspacing. Slide 27 highlights several recent business development activities.

First of all, Bayswater. As previously disclosed, earlier this month we closed our Bayswater acquisition in Wattenberg, which consolidates our oilier Prairie area into the northern portion of the field. The final purchase price after certain adjustments was $186 million plus approximately $14 million to complete 12 DUC wells prior to closing. The acquisition was adjusted to include about 7,400 net acres and estimated production of about 1,000 Boe per day. This acquisition brings about 220 gross locations to PDC that are included in our updated Wattenberg inventory count. Our second acquisition was from Saddle Butte pipeline, now Black Diamond Gathering, where they paid PDC approximately $24 million in exchange for extending the term of our Wattenberg crude oil gathering contract and increasing the acreage committed to the AMI. I'd like to note that there were no changes to the gathering fees as part of this transaction.

A key benefit of this transaction is that it strengthens our commitment to put more oil volumes on pipe and thereby reduce truck traffic. Our third transaction is our Utica Shale divestiture where we signed a definitive agreement to sell for approximately $40 million. We anticipate a first quarter 2018 close. The assets contain about 1,600 Boe per day and about 43,000 net acres. The benefit of the Saddle Butte Black Diamond Gathering and Utica transactions are that they cover about 2/3 of our 2018 outspend resulting in a reduction from about $90 million to about $25 million. This next slide provides an update to our 2019 corporate outlook, its model based on several input assumptions and based on where we currently sit today. The slide highlights our capital efficient portfolio that's capable of delivering strong sustainable production growth while strengthening the balance sheet and projecting a strong positive cash flow build in 2019.

Let's look first at some of the key input assumptions and corresponding outlook. Consistent with our prior 2019 outlook projection last fall, we continue to utilize just 6 total corporate rigs through 2019; 3 in the Wattenberg and 3 in the Delaware. We projected 3-year production compounded growth rate of about 33% with approximately 25% growth at the midpoint for 2018 and approximately 35% growth at the midpoint for 2019. Our outlook estimates capital spending of approximately $890 million at the midpoint for 2018 and about $1 billion at the midpoint in 2019. One of the key outputs of this scenario is that we project material free cash flow in 2019 of about $150 million at the midpoint as well as a year-end 2019 leverage ratio of only 1.0x. We believe these projected financial metrics demonstrate our focus on financial results, the quality of our portfolio and the strength of our team.

Implied in our 2019 projections are cash flow of about $1.15 billion at the midpoint and represents almost 2x our 2017 cash flow and that's based upon the $55 and $3 NYMEX price in 2019. So to summarize, this case demonstrates the company's flexibility to drive capital efficiency, our commitment to the balance sheet while projecting the material cash flow build in 2019. This final slide summarize what we project will be a very exciting 2018. Let me summarize several of our key initiatives for the year. First off, production growth to about 40 million Boe total at the midpoint in 2018 with the year-end debt to EBITDAX of 1.4x. Projected oil production mix of 42% to 45% with 100% growth in our Delaware production volumes compared to 2017.

Our outspend is projected to be less than $90 million and the proceeds from Utica and Black Diamond transactions are projected to cover 2/3 of that outspend. In Block 4, we're pursuing downspacing tests in the Wolfcamp A of 12 equivalent wells per section and we're also testing our first Wolfcamp C bench. And we continue to focus on margins with LOE projected less than $3 per Boe. In closing, we want to thank our employees for their strong contributions to the success of PDC. And with that, I'll turn it over the operator for Q&A.

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

Just to jump back to the gas realizations, obviously the guide of 55% to 60% is a little bit lower than what you guided towards in '17. Am I hearing it right that that's entirely a function of the accounting between TG&P and realizations that Scott talked about or is some of that a function of these newer processing facilities extracting a little bit more from that gas stream?

It's a mixture of 2 things I would say. One is the new rev rec guidance which is moving about $15 million to $20 million, which we would have previously done in TG&P and it's moving it up to reduction to our revenue stream. Also in that is the widening basing differentials where those have increased in our forecast going forward about from 40% with our first budget to now more like 65% to 75%, the pace depending on the differential that we're using.

Okay. And then a quick one on the Saddle Butte Pipeline. That $24 million, is that -- is that going to be a one-time cash payment to you'll or does that come in via just savings on the per unit on the pipeline?

Welles, this is Lance. It's a one-time cash payment.

Okay. And then just one last one and this is probably for Scott or Lance. Can you give your broader thoughts on processing over the next several years? I mean [Nubon], O'Connor, Lupton; are all those combined going to be enough as we move to 2019, 2020 in your mind?

This is Scott, Welles. Really the way we see it right now the plant coming on in '18, we see that obviously drop in line pressure significantly over that -- over where we sit today particularly and then we're really needing that plan in 2019. We think we're going to start to see some pressure increases in early '19. We're not sure that it will get as high as it is today. But then that Plant 12 negotiations that we're involved with is something that we see is another important step in DCP helping to alleviate the line pressures that we've seen over the last several years in increments obviously not consistently and it's something that we're really excited about where that takes us from a less frequent installation of these plants to a much more calculated and timed system. We feel like we really got it well in hand at this point.

Okay. And then on the non-DCP plants, should we think of those as helping alleviate pressures for you'll such as the Lupton or the Latham and what have you, should we really just be focused on the DCP ones?

Much more so on the DCP although we do have a fairly significant portion of our gas going to Arka, which offloads on to the Anadarko system a portion of their gas and with that comes some flexibility around where that gas goes and our teams have done a really nice job trying to move volumes where there's room to get them processed get them off to the sites. So it's something that helps, but it's much more -- obviously with our volume associated with DCP, we are much more focused on DCP.

Our next question comes from Asit Sen with Bank of America Merrill Lynch.

Could you provide a little more color on the production cadence? Was wondering if you could provide assumptions of Delaware contribution in your 130,000 barrels a day exit rate for 2018?

We really haven't given numbers on the Delaware contribution and so I'm going to pass by that and talk a little bit more about production cadence. One of the things as we put out these numbers that we put out recently or just in this release, we're definitely seeing where Wattenberg is expected to be fairly flat in the first quarter, the second quarter maybe a slight uptick and then with the plant coming online, we get a much more accelerated gain in production through the third and fourth quarters. So, really that is the best description with a fairly consistent growth I would say across the Delaware assets. Hopefully that gives you some idea where we're headed.

That's great. And then on Slide 12, looks like your best well I think 1,005 feet per day is well above your average. Can you provide any color on this well; zone, geology, anything that potentially you believe the results could be repeatable?

I think it's a little early to say that we'll get all of them to that pace. I think that's the first thing I want to state. But our team did a tremendous job of determining the -- as I described in my comments earlier, determining the issues that get in the way of having an efficient operation and you can see it improving through the year. It's such that the well is in an area where we feel like we can achieve that and it's a well also that is something that we would have a significant number of. So when we get to the point where we're talking about can we achieve that real short term, the answer is I wouldn't expect that at this point. But over a period of the next year or so, I think we could start to look at that kind of a number as a much more consistent number.

Great. And last one from me. Well cost $9 million to $14 million guidance, could you talk about the variable that takes us to the low end versus the high end, zone, length, et cetera?

It's mostly lateral length is on the high -- on the low end with 1 milers, with 2 milers on the high end. There is some variation in the different areas of the casing design, some of the completion designs; but really the result of the low end is 1 milers and the high end is 2 milers.

Our next question comes from Mike Scialla of Stifel.

I want to think -- how you're thinking about the priorities for the use of your excess cash flow in 2019 if your forecast is correct?

Mike, let me start with it. As Lance said, we've got a 35% midpoint production in our outlook and that's with 3 rigs and 3 rigs as he covered. So, I think we're really comfortable with that level of production growth. I think when we get to the budget process if we've got free cash flow, we'll give some consideration to adding some DUCs and accelerating and then we may give some consideration late in the year to adding some rigs, which would really be a 2020 move on our production growth. So, those are 2 capital spend moves that we'll give some consideration. But I don't think we want to market looking at us for trying to ramp that 35% midpoint growth up dramatically next year. Then the second thing I think that is a big focus for the company is our 2 milers. And Lance and his team I think have strong focus in both basins of trying to block up some acreage to give us additional inventory A and give us the ability to continue to drill the 2-milers which I think everyone understands are the most capital efficient. So, I think those are the 2 priorities. And then lower priorities, which we seem to be getting questions around which is new for a company our size, but that is share repurchases and dividends and right now I would say those 2 moves are probably lower on our priority list.

That helps. Wanted to see -- Scott, you talked about the differentials widening in some of the basis swaps that you've done. Any thoughts on -- or concerns I guess in getting your gas to market in the Permian? Have you taken any additional firm transporter, any agreements there?

So Mike, this is Lance. So in the Delaware, we don't see any issues getting our gas to market. There's a large extension that's going to be coming out of Waha. Kinder Morgan has announced a pipe there that I think is sometime in '19 that's going to add I think nearly 2 Bcf a day coming out of Waha there. Do we look at opportunities to lock in some firm transportation to improve netbacks and our overall margins? Yes, we continue to look at those and review those opportunities for the company and so our marketing team is very much dialed into that and has a good pulse on that. So, we continue to monitor that and if it makes sense, we'll take a very strong look at that.

Okay. And then last one from me is I guess more of a housekeeping question. You didn't really change your 2018 production guidance, but you did announce the Utica sale here. So, should we assume that we don't need to adjust the production for that Utica sale? I know it's not a big piece of production, but okay to just leave production where it is right now?

Mike, I would say yes, clearly it's in the range. If you look at the 1,600 Boe per day on the Utica there, we are projecting a close year-end -- excuse me, at the end of the first quarter at the end of March. So, there'd be about 3 months' contribution of that production in that rough range.

Our next question comes from Irene Haas with Imperial Capital.

I would like to ask you basically in Delaware Basin, what are your spacing assumption per bench right now or -- and also any spacing tests that you have planned? Then my second question has to do with how much is left for you to do in terms of drilling the whole acreage and how soon would you be able to tackle the Bone Springs?

So Irene, so our new spacing assumptions that includes the 200 potential additional locations. Let me start with Block 4. Block 4 is now estimated to be 12 wells in the A bench and 6 wells in the B bench for a total of 18 wells per section. And so that's our forecast and that's our estimates for the Block 4 Area. We are, as you know, testing with our Grizzly Bear 6 wells on half a section which equates to the 12 well per section equivalent test. So, that's a test that we should begin to have results on mid-year. Then secondly, if you go to the North Central area, we have updated our inventory to have 12 wells in the A bench, 4 wells in the B bench and then 2 wells in this area for the C bench. Again, a total of 18 wells per section. So, that's the basis primarily of the 200 location count increase in these oilier areas. As far as holding acreage, our rough estimates at this point in time is that it will take -- we usually take about 2 drilling rigs this year. We expect 2 drilling rigs or so to maintain and hold our acreage position and to help us with the continuous drilling provisions there with the 1 rig working on additional testing like we just talked about.

And how soon can you take a crack at the Bone Spring intervals?

That's a really good question, Irene. We're obviously doing a bunch of science work on that as we speak as we drill these wells. We're taking a look at and we're logging the sections and understanding more about the rock. With our current situation, we don't have anything planned for 2018. We may be able to look at that in 2019, but we're definitely seeing activity outside of our particular group of wells, which is a very positive thing for us and we're hopeful that we can not only learn from our science, but the science and work that they're doing that's in the neighborhood there. So at this point not '18, maybe '19.

Our next question comes from Paul Grigel with Macquarie.

I guess first on logistics down in the Delaware Basin, do you guys have any commentary or an outlook on any water handling needs, both inbound and outbound, out of the wells down in the Permian?

This is Scott and we've got a tremendous amount of work going into that. Our team is working very hard as I described to build pipe both for oil and gas takeaway as well as to manage the water and with the water comes both the water supply and the water disposal. We've been adding water disposal wells, at the same time we're still contracted with third-party companies to take some of the water away and we see that we're going to need both of those to get the job done. As far as water supply, there's 2 things there. We continue to add water supply wells, but we're also building a facility particularly in the eastern part of the acreage there where we're really blocked up and have a lot of activity. We've started building the infrastructure to recycle water. So, we are running down that pad very quickly and expect actually on I think either the next pad or the pad following that to start using some recycled water. So we've got a bunch of different efforts going on on that front and at this point, we see that as something that we've got a good handle. Our team -- like I said, our teams are working hard to maintain that and recognize it's critical for -- on both side, both in the supply water for the fracking and in the takeaway if you want to call it that a disposal process on the production side.

Okay. And then I guess changing terms a little bit. You guys commented on potential for free cash flow creation in 2019. Has there been any decisions made at this point in time on changes to the management compensation, incentives for 2018 going forward specifically focusing on either returns or free cash flow?

No, there's been no discussion around that.

Are those things that are being considered at this point in time or should we expect kind of similar to what last year's proxy entailed?

I don't know if there's anything I can discuss as far as what's being considered. I'm sure as we continue to refine the outlook, we'll be having those discussions with our board if any changes are needed.

Our next question comes from David Deckelbaum with KeyBanc.

I wanted to ask you guys on the 2019 disclosures -- 2018 you all walked up the oil mix. It looks like there's an implied oil mix increase in '19 along with some price improvements that leads to that better free cash generation. I guess as I look at it, it looks like you are baking in some slightly faster cycle times in '18. Are you carrying those faster cycle times through into 2019 right now or any performance improvement so far?

And when you say cycle times, you're talking about drill times?

Yes, especially I guess in the Delaware.

I mean for 2019 looking at our outlook, I would say that our plan for the Delaware is very similar to 2018. I would say the one difference in '19 which generates as you can see on Slide 28, a little bit more capital investment is we'll probably be turning on a few more wells in the Wattenberg as we start lowering our number of DUCs in the basin. With the additional Midstream capacity, we will be able to produce those wells without adding or taking away from our other wells and our other production. So I think that's what's leading to a little bit more capital intensity in the 2019 numbers compared to 2018.

And Bart, it sounded like before you wanted to emphasize that we really shouldn't think of much of a change to the '18 capital program or rig cadence program that it could potentially be something considered for the end of '19, which would see the '20 program. Is that kind of how you're thinking of it now? And I guess if you guys really are continuing this performance improvement in the Delaware, why might that not be addressed sooner?

We've got a lot to think through. Obviously we're giving an outlook with this 3 and 3 rigs so when we get to our budget cycle in September, October, November; we'll be looking at everything. But right now, David, with the growth levels we have forecasted in '19 plus a lot of flexibility around completion pace in the year; we've got the ability to move that production into the positives, probably spend a little bit more money, some of that cash flow. And like I said if there was any move we made, I think it would probably be somewhere late in '19 of giving depending on how Wattenberg is performing, how the midstream in Wattenberg is performing and how our performance is in the Delaware of deploying an extra rig maybe in one of the basins, I'm not sure we'd go in both. But that would be a shot in the arm for most likely our 2020 production. So, I think that's a real high level way we look at it and it's nice to have the flexibility and even have this discussion and we're proud of the teams and the way this has involved. But we're going to have to take a hard look at this as we go through the year and obviously we've got prices in here, right now things are pretty, pretty optimistic. But we're still cautious on the oil price, we recognize those things that could move that back into the $50s.

And if things move back into the $50s, this plan still remains relatively the same?

Yes, sir. As Scott Meyers said, this '18 guidance is built around an average of $57.50 a barrel.

Our next question comes from Kevin MacCurdy with Heikkinen Energy Advisors.

Just curious on why you think the oil cuts in the Delaware have been so much higher recently and whether you think that can continue in 2018?

Kevin, this is Scott. When we turned online those 5 wells that came online recently, they're actually shown on the graph, the oil contribution of that are very significant. There's the Grizzlys and there's 2 Buzzard -- 3 Grizzlys and 2 Buzzard wells in that mix and they're just in that 70% range for oil contribution. When you look at 2018, a big portion of the wells that we're drilling that had that were called the Grizzly Bear is in that same area as is shown on the [plot]. So, really that group of wells is driving it. When you look at what was contributing in the gas prior, we had a really strong Hermit well come on in, but it was very gassy. So, it's really that combination of things that have driven it toward the more oily side at this point. And as Lance pointed to, that 42% to 45% seems pretty reasonable at this point in terms of the overall outlook for the company for the year.

Okay. And regarding the inventory update in the DJ Basin, are working interest and the lateral lengths fairly consistent across the different areas or do they change?

They are highest in the Plains and Kersey areas. The working interest, I would say, are highest in the Plains and the Kersey areas and the Prairie area they are a bit lower in that area. And 1 of the initiatives that we have is working with offset companies to try to continue to block up and strengthen that Prairie area both with acres and working interest the same way. And that's 1 of the initiatives that we're focused on over the next 18 months or so.

And Kevin, it's a great question actually because I think when you look at the waterfall mapping that we have to the 1,500. The 1,800 locations had a 76% average working interest, you can see now we've got a 79%. So we've actually increased our working interest even though we have less inventory, but we also have longer average per well lateral feet.

And when you look at across the areas, the longest -- the longer laterals are much more in the Plains and Kersey area. That Prairie area definitely has shorter laterals as a part of it, which is what -- why Lance described that we'd love to continue to block up there.

Our next question comes from Tim Rezvan with Mizuho.

I want to pick at the topic of midstream a little more. Looks like $37 million in CapEx last year and it looks like $60 million in '18. How do you see this spending sort of trend? And then you gave a big update last year at your Analyst Day. How do you think about highlighting the value over the next couple years once you get over the hump on infrastructure spending?

Tim, this is Lance. So as we think about our modeling going forward and how it relates to capital allocation to the Delaware midstream assets, we're using approximately 15% of our D&C capital for Delaware to solve for if you will the spend on the midstream side and that's very consistent with what you see in the 2018 allocation of capital. As far as value creation, we are working together with our teams in both the midstream group, marketing group and in our operation teams to really define the value proposition that can come from the midstream assets in the Delaware Basin. And so we're just getting started on really looking at the buildout, the capital that will be required for those buildouts, the throughput, the values that would be generated from that and that's something that we are kicking off here and looking at very closely. We've been out in the market with -- and for some time just talking about the potential long-term value creation scenarios that can come from our Delaware Basin midstream asset and that's the plan that we're still on. We're working towards that assessment. So that's something that will take us probably most this year, maybe first part of next year to ultimately finalize and get to the place where we know the long-term value creation that we can see from those assets. But we're very pleased with ownership of those, we're very pleased with the valuations that midstream assets can bring, but we got lot of work ahead of us that we've got to assess. So, that's what we're working on now.

Okay. And then sort of a similar topic in the Delaware Basin. I think it was Scott who mentioned in prepared comments trying to highlight the value in the Delaware Basin acreage that may not be visible. The 2018 activity very concentrated. How can we think looking to 2019 maybe putting rigs and other parts of your Eastern or Central block? I mean what are your thoughts on kind of getting more delineation work done across those properties?

There's a lot of work to be done here, Tim, I think is the answer to your question across not only the acreage that we have, maybe that we're not as focused on this year, but also in the other zones. So as we look, we're doing that -- that constant decision-making process around do we drill a C branch in Block 4 or do we venture into a different part of the acreage. The Bone Springs was brought up today, another one of those things that we haven't had a chance to test yet. And it's a constant process of okay, what do we need to know for those next steps we need to maintain our acreage, how can we go about doing that in the most effective form or fashion that we can execute on cleanly? And so, it's all of those choices that go together that we're really faced with on a constant basis and our teams are doing a good job not only looking at the data we're acquiring as we log these various wells both in the pilot holes and vertical sections as well as the laterals themselves. We've done some lateral logging as well and coupling that with our peers out there that are doing a bunch of work. So we're really watching all of that and making the decisions around what's a very complex puzzle to put together. Again back to when each 1 of these things happens, it's really difficult for me to say. We pretty well laid out 2018, but our teams are already starting to think about what do we need to do in '19 to deal with all the different expectations that we have and you're obviously pointing to 1 of those.

Okay. So, it's still too early to say if 2019 could be similar as far as 2 focus areas?

Yes, I think it's a challenge in 2019 to say what are the next steps that we need to pass on or to work through to get to that ultimate. What is the value here of the overall zones and acreage position we have.

(Operator Instructions) Our next question comes from Jeffrey Campbell with Tuohy Brothers.

On Slide 13, I was just curious how you arrived at your location choice for the first Wolfcamp C test. Was this purely internal geologic analysis or maybe seeing peer results that helped to de-risk it in any way?

I would say it's much more of our assessment of the acreage based on the work that we've done in terms of logging that type of thing. It's a good spot because we already have a rig there, it's early in the year which we like, gives us a chance to really see that production say mid-year, probably later in the year. I spoke a little bit like we might see production data from the Grizzlys in the mid part of the year, but it's probably a little later in the year before we see enough to make any choices. But it's all of those things that went into that decision and it's, like I said, a good spot where we have a rig coupled with data down there from our testing and the idea that it's early in the year.

On slide 14 Lance earlier you was mentioning spacing assumptions in the North Central area, I was just wondering could you identify the locations that you're going to complete those 10 wells in in 2018? I mean the intervals?

The specific intervals? I may have some of those --

I can do a little bit of good there. Probably in the Greenwich area, we're looking at a combination of As and Bs. With the 5 wells in there, I believe we'll have 2 As and 3 Bs or reverse of that. The specifics I can't remember exactly. Again the others are a combination of As and Bs. I don't believe we have -- we don't have a C layered into this process out there at this point, but something that we'll be looking at in the not too distant future.

That was quite helpful actually. My last question, you've talked a lot about blocking and swapping acreage in the Wattenberg, I just wondered do those kind of opportunities exist in the Delaware Basin currently and is that something you're pursuing as well?

Jeff, it's Lance. From where we sit today, the answer would be yes. We spent time working with our business development group and talking with several offset operators there. We see a real willingness to sit down and look at ways that both of us can block up acreage to drill the longer more efficient laterals and we see a real willingness in doing that. So, that's something that we have initiatives kind of kicked off on that. We got lot of work in front of us, but we'd like to do a lot of the same type of consolidations in the Delaware like what we've been able to successfully accomplish in the Wattenberg area so.

And I'm not showing any further questions at this time, I'd like turn the call back to Bart Brookman for closing comments.

Thank you, operator. And just thank you to everybody for your ongoing support of the company and the great questions. Thank you.

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