Continental Resources, Inc.
Q4 2018 Earnings Call Transcript

Published: 20 Feb 2019

[Operator:]

Good day ladies and gentlemen and welcome to Continental Resources fourth quarter 2018 earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. [Operator Instructions]. As a reminder, today's conference may be recorded. I would now like to turn the call over to Rory Sabino, Vice President of Investor Relations. You may now begin.

[Rory Sabino:]

Good morning and thank you for joining us. I would like to welcome you to today's earnings call. We will start today's call with remarks from Harold Hamm, Chairman and Chief Executive Officer, Jack Stark, President and John Hart, Chief Financial Officer. Also on the call and available for Q&A later will be Jeff Hume, Vice Chairman of Strategic Growth Initiatives, Pat Bent, Senior Vice President, Drilling, Gary Gould, Senior Vice President, Production and Resource Development, Steve Owen, Senior Vice President, Land, Ramiro Rangel, Senior Vice President, Marketing, Tony Barrett, Vice President, Exploration, Josh Baskett, Vice President, Oil & Gas Marketing and Adam Longson, Director of Commodity Research. Today's call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially from those contained in forward-looking statements. Please refer to the company's SEC filings for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation to update forward-looking statements made on this call. Also this morning, we will refer to initial production levels for new wells, which unless otherwise stated are maximum 24-hour initial test rates. We will also reference rates of return, which unless otherwise stated are based on $55 per barrel WTI and $3 per Mcf natural gas. Finally, on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to Generally Accepted Accounting Principles, please refer to the updated investor presentation that has been posted on the company's website at www.clr.com. With that, I will turn the call over to Mr. Hamm. Harold?

[Harold Hamm:]

Thank you Rory and good morning, everyone. Thank you for joining Continental's full-year 2018 and fourth quarter 2018 earnings call. For many of you who have followed our progress for the past 11 years, you may grow weary of our consistently over delivering on our guidance. Thanks to our operations team, 2018 was no different. So at the risk of driving you over [there] [ph], let me once again cover a few of 2018 highlights. We promised you a breakout year and it truly was. First, financially we delivered approximately $1 billion of net income and net reduction of over $820 million to achieve our net debt target of $5.5 billion in 2018. Over the past two-and-a-half years, we have paid off almost $1.5 billion in debt from our peak debt levels and have decreased our quarterly interest expense significantly creating additional shareholder value. We also increased our year-end proved reserves by 14% over the last year. Second was our tremendous production growth and ever improving operational efficiencies as we progressed to full field wide development. We promised a new wave of oil growth and 14% sequential oil growth quarter-over-quarter best demonstrates this happening. This growth was driven by over 12% of oil growth in the Bakken and exceptional well results from our Project SpringBoard and STACK, all resulting in record production from our oil weighted production mix providing for 23% year-over-year production growth. Our teams accomplished this feat while delivering an industry-leading operational cost of $3.59 per BOE as compared to our oil weighted production peers, an enviable cost efficiency development, even when considering some of the harshest operating conditions, all horizontal, deep high pressure and extremely cold during these winter months. My hat is off to our operating teams and great job by all. Thank you. Lastly, our creativity and ingenuity has been engaged all year, every year to enhance shareholder returns. This was accomplished this year through the newly innovative mineral royalty relationship with Franco-Nevada which holds significant future growth potential as production increases from our SCOOP and STACK regions as we maximize value from these large resource plays now primarily HBP. Although this arrangement will start from a smaller entity, we expect this to germinate into a multibillion-dollar enterprise ultimately. Our vision forward gives us great confidence in continuing our upward projection for 2019 and five years ahead as we move from the 325,000 BOE per day production level. Our oil weighted production in the Bakken will drive our production rates higher just as the SpringBoard project adds significant oil production here in Oklahoma SCOOP play. At Continental, we have the internal sophistication to provide meaningful long-term growth plans. We provide our first five-year plan 2019 with plans then to triple production and we accomplished it in just 3.5 years. In 2012, we projected another five-year plan to again triple production and accomplished that even while growing HBP acreage. Our major plays are now primarily held and in full field development stage. Our vision is even clearer as to growing future production and generating free cash flow and shareholder returns as a result of newest five year vision beginning in 2019. Our vision over the next five years is to deliver a unique combination of several billion of free cash flow generation, while simultaneously nearly doubling our 2018 production from a much larger current production base. We plan to deliver significant and sustainable value to our shareholders driven by our strong free cash flow generation. We are the most well-aligned company with shareholders and are strongly focused on value creation. Since much of our business depends on world events, let's discuss the market macro a little bit. Last quarter, we talked about the one-time event of the unexpected Iranian crude oil purchase waivers causing a precipitous oversupply induced price collapse in crude last fall. We don't expect to see another one of those as the six-month window lapses. Apparently, there was a historic precedent to grant the one-time waiver to those purchasers. With the waiver grant and oversupply situation approximately one million barrels of oil play was created. That oversupply [wedge] [ph] took 4.5 months to build up and will take about an equal amount of time to dissipate it. We are now into the fifth month following the grant decision and measures to correct the oversupply are in place and [oil] [ph] prices have been begun to stabilize and correct. Continental is well-positioned to benefit and participate as higher prices are once again returning to the market. Our 2019 budget reflects our fiscal discipline as we gauge rebalancing of [oil] [ph] supply. As always, we will remain flexible and nimble as we view opportunities for value creation and future growth during this period of global rebalancing for many supply centers, such as Venezuela who has currently lost market share due to political infighting there and may have longer-term marketing disadvantage as U.S. shale producers produce light sweet crude that disrupt and displace the heavy bitumen producers worldwide. Deregulation and growing infrastructure in Americas are placing the U.S. upstream in a new and unique position to supply global markets. Globalization of the U.S. supply is fast occurring in the marketplace. Both crude oil and natural gas infrastructure are being planned and constructed in the U.S. which will diminish and eliminate market differential between Brent and U.S. crudes as the domestic marketplace become focused on the Gulf Coast region for waterborne [neat] [ph] barrels and LNG. Approximately $55 billion of new infrastructure is being invested in the Corpus Christi shipping area alone. Continental has been supportive and instrumental in moving our product to the Gulf and has sent [neat] [ph] Bakken oil to parties serving the Asian and European markets. Access to global markets of our production is a primary focus of Continental's marketing strategy to normalize the differential between Brent and WTI and again, I salute our marketing professionals here at the company who have positioned Continental so well as new infrastructure is built out for those who supply world markets. We have established and secured additional firm transportation to the Gulf Coast region and it is nice to be selling the [indiscernible] barrel in the Gulf Coast and realizing WTI NYMEX minus $2 range at the wellhead North Dakota. Thank you. And I will turn the call over to Jack Stark.

[Jack Stark:]

Thank you Harold and good morning everyone. I appreciate you joining us on our call. As Harold pointed out, 2018 was an exceptional year for Continental on many fronts. As we delivered top-tier cash flow positive growth and a 14% return on capital employed. We call that our breakout year as it marked the beginning of a new era of sustained cash flow positive growth for Continental as we began to develop the deep inventory accumulated from years of grassroots exploration. Over 95% of our drilling activity is now focused on multizone unit development. Most importantly, with over 75% of our net reservoir acres held by production, we have the flexibility to adjust our pace of growth and development to sustain corporate returns and accommodate the prevailing commodity environment. This is an ideal position to be in to participate and grow value in today's new global oil market. Today I will provide some operating highlights from the full-year and fourth quarter 2018, followed by our plans for 2019 and our five year vision. Companywide, our 2018 production was up 23% year-over-year. Oil production was up 21% year-over-year and grew rapidly late in the year as fourth quarter oil production was up an impressive 14% over the third quarter of 2018, reflecting a shift to oil weighted drilling earlier in the year. In the Bakken, our production grew 26% year-over-year and 10% over the third quarter. Continental continues to be largest oil producer in the Bakken by a wide margin, operating approximately 14% of the Bakken production in North Dakota as of October 2018. Throughout the year, our optimized completions delivered record company results and outstanding capital efficiency. As proof, our 2017 drilling program has already paid out and our 2018 drilling program is 60% paid out at this time. Results in the fourth quarter continue to impress as we completed 52 operated Bakken wells that flowed at an average initial rate of 2,800 BOE per day per well and approximately 80% was oil. Four of these new wells were added to the top 10 list of Bakken producer for the company based on their initial 30 day rates. In Oklahoma, our development activities in SCOOP and STACK were in full swing in 2018. Combined, these assets grew production 24% year-over-year. Of note, fourth quarter oil production in SCOOP grew 47% over the fourth quarter of 2017 as production from our SpringBoard project began to grow. We turned 22 Springer wells to production in SpringBoard during 2018, most of which came on in the fourth quarter. Combined, these 22 Springer wells have produced, on a gross basis, around 2.3 million BOE and are currently flowing approximately 13,300 gross BOE per day with 81% of the production being oil. The project is moving along on schedule with 18 Springer and 27 Woodford and Sycamore wells currently waiting on completion. As previously guided, SpringBoard is on track to grow company third quarter 2018 oil volumes by 10% or approximately 16,500 barrels of oil per day by the end of the third quarter 2019. Slide 12 in the deck shows SpringBoard is on track with fourth quarter production averaging 5,260 barrels of oil per day. In STACK, we achieved strong repeatable results during the year from our unit development activities in the over pressured oil and condensate windows. In the fourth quarter, we successfully developed another condensate unit in STACK called the Boden unit. The Boden unit included three wells targeting a single Meramec interval. The Boden wells flowed at an average per well rate of 4,700 BOE per day and 1,200 barrels were oil. These Boden wells are strong producers outperforming the parent type curve by approximately 40% in the first 60 days. This is the fourth unit we completed during the second half of 2018 utilizing unit development model we introduced last year. These forward units are meeting and exceeding our expectations and provide the template for the 65 operated units that remain to be drilled in the overpressure oil and condensate window. Including the Boden wells, a total of 19 wells were completed in STACK during the fourth quarter, flowing at an average initial rate of 3,645 BOE per day per well. In addition to the outstanding performance from our assets, our teams continue to drive down costs through added operating efficiencies. In the Bakken, our completion teams have demonstrated a 45 stage limited entry completions deliver similar results to our standard 60 stage completion. By treating the same number of perforations with fewer stages, we save approximately $200,000 per well, reducing the Bakken well cost to $8.2 million per well. In SCOOP and STACK, our drilling teams are working on additional efficiencies in our Woodford, Sycamore Meramec programs that could save up to $650,000 per well. These savings are not included in our 2019 budget, but represents significant potential upside during the year as these become standard operating procedure. For example, in our SCOOP Woodford and Sycamore programs, efficiencies gained in the second half of 2018 are translating to an incremental savings of $500,000 per well. This is on top of the $1 billion in savings we announced earlier last year utilizing our new wellbore design. In STACK, our teams are ready to test a new wellbore design that could reduce the cost of well by up to $650,000 per well. We will keep you posted. Now let's move on to 2019. As we announced last week, our budget for 2019 is set at $2.6 billion. This is down approximately 9% from our 2018 non-acquisition CapEx. Our priority in preparing our 2019 budget was to ensure we generated adequate free cash flow to continue to reduce debt targeting $5 billion in net debt by year-end 2019. At $55 WTI and $3 gas, we expect to generate approximately $500 million to $600 million in free cash flow and 9% to 12% annual return on capital employed from our 2019 activities. Our production growth will be oil weighted with oil production growing 13% to 19% and gas production growing 1% to 4% year-over-year. Approximately $2.2 billion or 85% of the budget is allocated to drilling and completing an estimated 257 net wells during 2019. The capital expenditures are essentially split 50-50 between Bakken and our Oklahoma assets in SCOOP and STACK. We plan to operate an average of 25 rigs during 2019, down from 31 rigs at year-end 2018. Six of the rigs will be focused in the Bakken and 19 in Oklahoma with 12 of the 19 focused on our SpringBoard project. Details are provided on slide 16 in our deck. As we look to the next five years, we do so with confidence that we can continue to deliver strong returns and top-tier production growth, thanks to the quality of our assets and efficiencies of our operations. Over the next five years, we are targeting production growth at an average annual compounded rate of 12.5% while targeting average annual free cash flow in excess of $500 million. Now I want to point out the words in excess, which we inadvertently left out of the press release last night. To clarify, we are expecting average annual free cash flow closer to $700 million to $800 million with an actual range of $500 million to $1 billion or more per year. We apologize for this confusion. Over the five years, we project return on capital employed to be in the 14.5% range, improving in latter years as we see continued improvements in capital efficiency and corporate returns. All of this is calculated based on $60 WTI. Approximately 50% to 60% of the total growth will come from the Bakken and 40% to 50% will come from the Oklahoma. During these five years, we expect to develop less than 30% of our current inventory delivering an impressive blended average rate of return of 60% assuming $60 WTI. At $50 WTI, the blended rate of return would be approximately 40%. This of course does not include further efficiency gains we fully expect to realize during this time or any upside from technology or inventory growth through exploration. Now this five year vision was meant to provide a framework on how we see the company evolving from here offering competitive oil weighted growth, significant free cash flow and strong corporate returns. I just wan to point out, this vision was not meant to be utilized as a granular company five-year guidance. Going forward, we plan to maintain a multiyear outlook to frame expectations to make clear the sustainability of our growth and corporate returns. The guidance will be on a region specific basis as shown on slide five with the North region dominated by the Bakken and the South region being a combination of our SCOOP and STACK assets in Oklahoma. This guidance will focus less on describing our activity based on type curves alone as we move to multizone unit development. Maximizing value through multizone unit development involves STACK reservoirs with different performance drilled in various combinations, the timing of which varies depending on the size of the pad, rig count, stim crew counts, facility, market dynamics, et cetera. So as a result, multizone performance is difficult to characterize based on type curves alone. So with field wide multizone unit development underway, we are just beginning to realize the true value of our assets for Continental and its shareholders. So please follow our leadership as our large resource plays have evolved to full field wide development. And with that, I will turn it over to John.

[John Hart:]

Good morning. Let me start with an overview of our 2018 annual accomplishments. Back in early 2018, we suggested that 2018 would be a breakout year for Continental with targets to generate significant free cash flow to be utilized for debt reduction while also targeting production growth of 17% to 24% year-over-year. We have executed at a very high level. 2018 has set the stage for our vision for the next five years with year-over-year production growth of 23%, net debt reduction of over $820 million and nearly $1 billion in net income. Continental hit our 2018 year-end debt target with approximately $5.49 billion in net debt in December. We are on track toward our longer-term net debt target reduction of $5 billion, which we anticipate achieving late in 2019. We expect to redeem $400 million to $600 million of our outstanding 2022 5% bonds in 2019. This will be funded by cash on hand and temporary utilization of our revolving credit facility and will likely be in the near-term. Returns for 2018 were solidly within guidance with the return on capital employed of approximately 14%. This is an overall return that notably distinguishes us against industry peers, but also against other industries. I would refer you to slide seven in our investor presentation to see how our corporate returns compared to the broader market. As Jack noted, we expect to see continued strong returns on capital employed over the next five years as we execute on our vision and continue our long-term emphasis on generating strong returns. A good optic here is return on capital employed is projected higher in year five versus year one. In other words, it's improving throughout the five-year horizon. Underpinning our 2019 returns is strong performance against a variety of cost measures. We generated peer-leading oil weighted production expense coming in at $3.59 per BOE in 2018, while also generating exceptionally low G&A per BOE of $1.69. For a company our size, our G&A is relatively low with an employee headcount of approximately 1,200. This combined with our results generate exceptional productivity per employee. Finally, I will note that our DD&A per BOE continues to decline. While we don't typically discuss this measure, it is a strong optic exhibiting our continued improvement in capital efficiency driven by well productivity and capital discipline. In line with growing returns on capital employed, we envision continued improvement in our DD&A rate throughout the next five years. As mentioned during our third quarter conference call, the company expected higher oil differentials in the fourth quarter due to heavy refinery maintenance season and Clearbrook's impact on Bakken differentials. Well, Continental does not sell into Clearbrook, Bakken oil differentials were impacted late in the quarter, which led to a higher than expected corporate oil differential for the year. First quarter differentials are evidencing an improvement with sequential monthly improvement resulting in significantly better differentials than the fourth quarter. CapEx in a bit higher than forecasted for 2018 at $2.8 billion as we added rigs in the second half of 2018 before the late fourth quarter oil price decline and accelerated our purchase of mineral royalties. As you know, mineral royalties are largely reimbursed by Franco-Nevada. As you can see in our 2019 budget release, we are moderating rig activity to align with the $55 oil price environment. We remain committed to operating in a capital efficient manner to grow production while generating strong cash flow for debt reduction. We are extremely nimble as we are not burdened by significant long-term contracts. Rig count, year-over-year, is expected to be relatively flat, which is a decrease from the fourth quarter. We have begun these reductions and expect to continue over the near-term. As Jack stated, the 2019 capital budget is projected to generate approximately $500 million to $600 million of free cash flow for full-year 2019 at $55 per barrel WTI and $3 per MCF Henry Hub. This level of cash flow will provide the company the ability to reduce debt to our $5 billion target and begin considering implementing a sustainable dividend in the future. A $5 change for sensitivity per barrel of WTI is estimated to impact annual cash flow by $300 million to $325 million. And the company's current capital plan is cash neutral at a mid-$40 per barrel WTI. Of the total $2.6 billion budget, the company is allocating approximately $125 million to our previously announced minerals agreement with Franco-Nevada for royalty acquisition. With a carry structure in place, the company will recoup $100 million from Franco-Nevada and earn 50% of total revenue in 2019 based on our already achieving certain predetermined production targets. Continental will include the total $125 million in our consolidated CapEx but will be reimbursed monthly by Franco-Nevada. While revenue from our minerals was minimal in 2018, we are beginning to see growth in royalty revenues as SpringBoard comes online where our minerals venture owns 17% of the net mineral acres underlying our leasehold. The company expects to generate significant revenue from these minerals over the next few years as we focus our acquisitions in ongoing density development areas. As I mentioned during last quarter's conference call, we have provided specific guidance on oil and gas volumes separately for 2019 to facilitate your understanding of Continental's oil weighted production growth. You should expect to see strong 2019 oil volume growth of 13% to 19% over 2018. We also expect to generate 1% to 4% year-over-year gas production growth. While we focus on oil and gas volumes, respectively and not the hydrocarbon percentage, we do expect the oil percentage to climb with our oil focus. Our guidance for 2019 cost measures exhibits expectations for strong performance. LOE is guided slightly higher than 2018, due to our emphasis on oil weighted growth, which obviously has a different volumetric ratio the natural gas. The key is, oil also has stronger margins relative to natural gas. For 2019, we have guided our oil differentials from a range of $3.50 to $4.50 in 2018 to a range of $4.50 to $5.50 for 2019, due in part to our even greater Bakken oil focus in 2019. Bakken differentials are higher than the South due to the South being nearer to Cushing and we risked a bit more this year due to recent volatility. We do expect a significant expansion of Bakken pipeline and gas processing in the near future and long-term as well as continued infrastructure directed towards coastal markets benefiting our differentials. This is already benefiting improving differentials. While numerous companies will speak to production growth and free cash flow, we are one of the few that consistently delivers leading results for each measure and we will continue to do so. With that, we are ready to begin the Q&A session of our call and will turn it over to the operator to take questions. Thank you for your time.

[Operator:]

[Operator Instructions]. And our first question comes from the line of Doug Leggate from Bank of America. You may begin.

[Doug Leggate:]

Thanks. Good morning everybody. So Jack and John, I think I speak for a lot of people in thanking you for the clarification on the free cash flow, but if I may, I just would like to underline that a little bit. So just to be clear, the $55 number you gave, I guess, last week, is now $700 million to $800 million out of $60 TI basis. That's what you said, Jack, right?

[Jack Stark:]

Yes. We gave $55 that's for the current year budget because that's relative to where the market has been. Obviously, it's improving off that here recently. Obviously, we have a higher expectation for the longer term. So we are giving you a lot of sensitivity and what you can see in various ranges in $5 type ranges to trying to give you more color and transparency.

[Doug Leggate:]

Well, as you know, that kind of detail is never enough for guys like us. So my question actually is, can you give us some idea, obviously you have given us the growth outlook as an average, but can you give us some idea what the CapEx assumption looks like? How that evolves? And if I may tag on another detail, if you are prepared to go into it, is what happens to your cash tax outlook as you move into that five-year view?

[John Hart:]

Great questions. Let me give you more color than you probably want. Let's look to 2019 first. First and second quarter will be sequentially lower as relative to the fourth quarter of last year. I would say, they will be slightly above and below the average, if you just took the four quarters and averaged them on our capital budget. Third quarter will be a bit higher than that. And then the fourth quarter will be lower. That's all based on project timing. As you know, we have got large multi-well units and multizone. So we have got big projects. So the timing can vary, but they are not all that different, but just to give you a little color on the transition. So that's 2019. As you look to the five-year where we have modeled our 2020 and 2021 are kind of in the low $3 billion type total CapEx range. And then the latter years, 2022 and 2023, are in the mid-$3 billion, from a CapEx standpoint. We are growing. We are growing that production on a larger base. So you are putting up a lot more cash flow as you are growing and you are also utilizing a bit higher CapEx. But it's not a huge amount, but it obviously is a bit more as you go through it on a bigger base. In question regards to your cash tax question, we don't envision that really changing over the five-year horizon. As you look to our balance sheet, you will see that we have significant deferred taxes which are primarily composed of net operating losses on the federal level and then also in our larger states, North Dakota and Oklahoma. So I don't think you won't see a cash tax change.

[Doug Leggate:]

Okay. Thank you for that, John. My follow-up, if I may. I would love to ask Jack five questions. But I am going to let someone else do that. So I am sorry, John, I will stick with you for a minute. But line of sight to hit your $5 billion target, what happens after that? And you know where I am going with this. Specifically I am looking for some idea what your thoughts are on dividend and specifically maybe a variable upside component to that dividend, because it looks like once you hit your debt target, you are probably not buying back stock is my guess. What will you do with the cash? And I will leave it there. Thank you.

[Jack Stark:]

The good point is we are going to have a lot of cash. So we have got a lot of options with what we do with it. We will look at all of those options. I think the key there is balance. I am not aborting the question. But we do need to think in terms of balance. Some could go into further debt reduction. There is nothing that says paying debt down further, eliminating more interest expense, benefiting cash flow, that's certainly valuable. In regards to dividends, that's something that we have clearly spoken to. We continue to discuss that internally. That the discussion will be ongoing. I think you could see us and when you get to that $5 billion range, that's the timeframe that we could be more likely to implement that. Obviously that is up to a prospective decision by the Board of Directors. To your question on variable, I think that's fair. We would put something in place that we deem to be sustainable in the longer term price tested environment. So something that's sustainable in a $40 price environment that would be more nominal. As prices go higher, I think we could have mechanisms to where we could return incremental cash to shareholders in a higher environment. We certainly have that ability, but we would look at it in combination with further debt reduction, a dividend level and then frankly we have got a huge asset base and a very deep inventory. Some of it would probably go back into investing a bit more. So I gave you a long answer, but it's really an answer of balance in how we look at all of those factors. But all those factors would be employed and would be considerations. The good point is we can do it. We can generate the cash and we can generate the returns.

[Doug Leggate:]

I appreciate all the clarification guys. Thanks a lot.

[Jack Stark:]

Thank you Doug.

[John Hart:]

Thank you Doug.

[Operator:]

And our next question comes from the line of Drew Venker from Morgan Stanley. You may begin.

[Drew Venker:]

Hi everyone. Harold, I wanted to address the comment you made in the release that 2019 growth can adjust to market conditions. Can you just share more thoughts about how growth and spending and free cash flow might change at higher or lower prices in both 2019 and the next five years?

[Harold Hamm:]

Well, we do expect higher oil prices. As we come out of this one event, cataclysmic deal, happened last fall. So as it comes about, we have one thing that's related to this five year inventory out. Very apparently, we have a very, very deep inventory. And so we have stepped that up. But we always want to keep an eye on the market and not oversupply it. We realize that it is, the world market, is fragile. It's not that we are going to tip it exactly but we certainly need to be aware of it. So we could step it up, if need be and develop more inventory as we go forward. And John said, dividend, definitely it could play a part in it. So I hope I have answered your question.

[Drew Venker:]

Yes. I guess, Harold, just to clarify. So at higher prices, you would likely spend a bit more than what you have laid out in that case, based on $60? And in lower price spend somewhat less?

[Harold Hamm:]

Yes. Absolutely, Drew.

[John Hart:]

Obviously, we always look to the price being sustainable and we would look to the broader supply and demand. We don't react to weekly, daily type prices like you see others do some time. So something that's sustainable and [indiscernible] clearly we have the assets.

[Jack Stark:]

And Drew, this is Jack. I just want to stress this point you are likely making here too is that we have the flexibility to do this. And our assets are secured, as we have said, 75% of the net reservoir acres are HBP'd. And it's a real strength of the company to have the flexibility to be able to adjust.

[Drew Venker:]

Understood. Thanks for the color. Just one follow-up on capital allocation and use of free cash. At $5 billion of net debt, I think you will be at a healthy level for leverage ratio. Is there a desire to get that ratio down further beyond the end of this year? How are you guys thinking about that?

[John Hart:]

The billion magic of the $5 billion is stress tested in a $40 price environment that keeps us below two times debt to EBITDA. So that's the magic of how we got there. In a current price type environment, you are down around one times debt to EBITDA. So that's pretty strong stable debt ratio. That's why we referenced that point as where we begin to consider implementing a dividend and that can be a target type area. As we go beyond that, I think you could see a balance where we continue to pay down debt, while also having those other opportunities for dividend and reinvestment. If you just look to our callable bond structure, you could go all the way down to about $4.2 billion. So I mean, if you want to know where ultimately we go, it's certainly down to that level. Beyond that, if you look out towards the end of our five-year horizon, we have got about $1.5 billion of bonds coming due out there that are currently non-callable. We are generate enough cash flow that we could redeem those out when they come due out there, if we chose to. So a lot of cash flow gives us a lot of flexibility.

[Drew Venker:]

Thanks John.

[John Hart:]

Thank you Drew.

[Jack Stark:]

Thanks Drew.

[Operator:]

And our next question comes from the line of Bob Morris from Citi. You may begin.

[Bob Morris:]

Thank you gentlemen. You have kind of hit a lot of the points here on the flexibility, on the free cash flow and being able to dial up or dial down depending on the oil price. And Harold, I know you are very bullish on the oil price from here. My question is on, as you look to your balance and targets, do you have a target on ROCE or on free cash flow yield that sort of helps you talk about because you have now put in the slide comparing your free cash flow yield to the rest of the industry which is good, but at the same time, as you look at ROCE obviously at a higher oil price, the more you reinvest which you mentioned is an option for that free cash flow, the higher your ROCE goes as opposed to paying down debt or paying a dividend. So I was just wondering, how do you look at the targets on free cash flow yield and ROCE?

[John Hart:]

Let me give you some sensitivity there. On 2019, we have guided, at $55, it's 9% to 12% type percent. At $60, it's about 4% higher on each end of that. So you are looking more in the 13% to 16% type of range at $60. So there is a little bit on price sensitivity. Obviously, your point on investment dollars and what the quality of inventory that we have and strong returns that that generates, accelerating some of those can improve that as well. If you go back and look over the last 10 or 11 years, we have averaged in the 19%, 20% type range depending on how you calculate it. It can even be a few percentages higher than that. There are number different methodologies. So we see improving through the five-year. Well, we see putting off that strong cash flow and other things and having that ability to reinvest. So the latter years are higher than that average and whether they go higher than that can depend on some of the decisions. But we want to be a very strong competitive return on capital employed, not only against E&P companies, but against all sectors. And that's we have laid it out in the slide and I think you should look to us for generating superior top returns.

[Bob Morris:]

Great. Thank you for that color.

[John Hart:]

Thank you.

[Harold Hamm:]

Thank you.

[Operator:]

And our next question comes from the line of John Aschenbeck from Seaport Global. You may begin.

[John Aschenbeck:]

Hello everyone and thank you for taking my questions. So my first one, I was hoping to follow-up on the differences in your free cash flow outlooks for 2019 compared to the five-year plan and maybe approach the topic a little differently, just to make sure I am following correctly. If I use your comments that a $5 move in crude equates to about $300 million to $325 million change in free cash flow.

[John Hart:]

That's for 2019.

[John Aschenbeck:]

For 2019, right.

[John Hart:]

It would be more than that as you go further out because in each of the subsequent years obviously because of the higher production base.

[John Aschenbeck:]

Right. Perfect. Okay. So I guess using those assumptions, are more or less getting applied free cash flow breakeven over the five-year plan that's very similar to the 2019 levels, more or less in the mid-$40s. Is that a fair assumption that your corporate free cash flow breakeven price remains relatively stable over the next five years?

[John Hart:]

I think relatively stable, I would say mid-$40s to $50, maybe a $1 or $2 above that. It just depends on the individual year and the timing of projects of what capital we are deploying in that. The key point that I think you are going to is, it's not a high number. It stays very strong and competitive. It might be a few dollars higher than that mid-$40 but we are not talking significantly.

[John Aschenbeck:]

Okay. Perfect. That's exactly where I was looking to go for. I appreciate that.

[John Hart:]

That's a great observation. It is a very, very competitive amount for us.

[John Aschenbeck:]

Okay. Great. Yes, so for my follow-up question. I was just hoping to touch on CapEx a little bit, specifically really just get your overall comfort with the $2.6 billion capital program you have out there for 2019, which you obviously just put in place. But if I just compare that to Q4 2018, which came in at $740 million, it implies that your quarterly CapEx run rate in 2019 is going to need to come down versus where you were in Q4. So I was just hoping you could walk us through some of the variables between Q4 2018 CapEx and 2019's quarterly run rate?

[John Hart:]

I would say, rig activity is one of those items and we were little bit above 30 in the fourth quarter. We are coming down from that currently. Just the timing of projects factors into that a lot. We also had a larger level of mineral activity in the fourth quarter than we would potentially will. And minerals will not be divide by four. They are very opportunity specific and the timing of that can vary by quarters. For the first quarter, we are going to be somewhere in the $670 million type range. So that's obviously down significantly. Second quarter, as I indicated earlier, is lower than that. And then third quarter is a little bit higher and then the fourth quarter is lower than that. It's just driven by timing of projects and completion. But we do feel very good about the $2.6 billion. It enables us to set up the five-year horizon and to grow well here. Price has moved up significantly and we view them as stable as we spoke to earlier. I think you would see us accelerate the debt paydown quicker. So more of the dollars would go to that. But ultimately, if we chose to invest a little more later in the year to set up 2020 even stronger, that could be an option if the market is there. But we do feel good about where we are at and we feel good about our ability to deliver.

[John Aschenbeck:]

Okay. Great. That's it for me. I appreciate the time. Thank you.

[John Hart:]

Thank you John.

[Jack Stark:]

Thank you.

[Operator:]

The next question comes from the line of Brad Heffern from RBC Capital Markets. You may begin.

[Brad Heffern:]

Hi. Good morning everyone. I just wanted to dig in on the 60% average rate of return figure that you guys called out over the five-year plan. So just looking at type curves that you have for last year, all the major oil plays were above that figure. So I was wondering if there is degradation of well performance in there, if there maybe service costs or something else that will bring the average below what type curves were for 2018?

[Jack Stark:]

Sure. Brad, this is Jack. I appreciate the question here. What's really transpiring here is that the company has moved into multizone full unit development. And as you do that, you are going to see that you are going to be blending different zones. You are talking about multiple zones being developed within a given unit. And there are some zones that will definitely be the type curve wells and then are other zones in there that will not. But we are all about maximizing the value from these units and getting as much oil and gas out of these as economically as we possibly can. So we are blending in all zones when we do this, give you a 60% average rate of return for the year at $60 for the program, okay. And a good example would be, say, in the Bakken. When we go and drill the Bakken, we are drilling three different zones up there in many areas. We are drilling Middle Bakken, Three Forks 1 and Three Forks 2. And the returns on each of those zones will vary depending obviously on the EUR from each with often times the Three Forks 2 being the poor performer. And so it will bring down, say, the average overall for that unit but we are maximizing the PV and the value of that unit by developing it at that time. Because you really get one shot to develop these units and you want to go in and do everything you can to maximize the recovery and the net present value for those units. So kind of going forward, I think you really need to look at the returns that we are talking about here like we put out here for this five year vision. It's a transition from parent wells and some unit wells to full unit development, multizone development. And this is the next phase that essentially plays like the Bakken that are moving into this full unit development are actually going into. And so I think it takes some, I guess people just need to kind of get used to the fact that that's it. But if you look at the value we are creating out of these units, the returns may be degraded a bit, but the returns and values are fantastic. And obviously it's growing production. You take a look at our growth that you saw last year, 23% production growth year-over-year. And that is on top of paying down debt about $825 million, I think it was. And so you can just see the horsepower that we have in these units to generate cash and grow production. And it's just 2018 is kind of a good look or template for what you can expect going forward.

[Brad Heffern:]

Okay. Thanks. I appreciate the detailed answer. And then I guess, as my follow-up, just any new thoughts no A&D? Are there any packages that you guys are shopping? Or conversely, are you looking at acreage anywhere?

[Harold Hamm:]

Continental is always looking.

[Operator:]

Thank you. And our next question comes from the line of Drew Lipke from Stephens. You may begin.

[Drew Lipke:]

Yes. Good morning and thank you for taking the questions.

[John Hart:]

Good morning.

[Drew Lipke:]

Just thinking about the production variability around that 12.5% average over the five-year plan and I appreciate all the color there, how should we think about maybe 2020 production growth, just given lower activity levels in the Bakken? And then also thinking about the SCOOP with the amount of flush production tied to Project SpringBoard, is it maybe reasonable to assume that 2020 could be below that 12.5% average?

[John Hart:]

I think 2020 is fine. We feel very good about all years in the five-year plan. I wouldn't say Bakken is really lower level of activity. We are getting more per dollar spent than we ever have. The rig productivity and the well cost improvements, Jack alluded to some of those in the script, we are doing exceptionally well. As we look out over the five year horizon, we are seeing good solid growth throughout that. 12.5% is kind of the average, but it varies in that 10% to 15% or even a little better than that and frankly those low end. As we go out through the year through the plan, we will optimize and we will improve and we will get more per dollar spent. If you look back to our two previous five-year windows, we made those of targets and we made them quickly. And this is a plan that will almost double the size of the company. So that requires consistent results and good strong production growth throughout. So I think we are very comfortable with where we are at.

[Jack Stark:]

What I mentioned too, Drew, that our rig count in the Bakken really is basically equivalent on average for the year is equivalent to where we were last year. We had ramped up to eight rigs at year-end and now backed off to six. And so point of it is that really on a full year basis, our activity is very comparable.

[John Hart:]

And Drew, pickup also that like in 2019, the oil growth and the gas growth are different. So you are overcoming a decline in gas volumes at a 6

[Drew Lipke:]

Got it. That's helpful. And then just quick follow-up on the 2019 guide. You mentioned higher production expense per BOE albeit still at very low levels for heavily oil weighted operator. But with more capital being allocated to Oklahoma in 2019, just on a relative weighted basis, I would have thought production expenses might come down year-over-year. Is that just all attributable to the oil composition? Or is anything else going on?

[John Hart:]

It's the oil composition. When you are a gas company, you are dividing, but you get 6

[Drew Lipke:]

I appreciate all the color guys. Thanks.

[John Hart:]

Sure.

[Operator:]

Thank you. And our next question comes from the line of Neal Dingmann from SunTrust. You may begin.

[Neal Dingmann:]

Good morning guys. I just wondered if you could maybe give me little bit more details on how you are thinking about first quarter CapEx, I think you said around $670 million and the full year of $2.6 billion, given your comment that production, I think you said, might be down a little bit in 1Q. I guess what I am hoping for is maybe a little bit more on the timing of the large projects and how might that impact the CapEx for the year?

[John Hart:]

I wouldn't say the production will be down in Q1. I am not sure where that one came from. We exited 2018 at a very healthy level, almost 325,000 a day. I think you will see us maintaining or growing that a bit earlier on and then you see stronger growth later in the year. Again, we are focusing more on oil and the timing of this project. So it's just when they come on. They are large units like SpringBoard. We talked about the cadence of SpringBoard before. It will be coming on over the next, certainly through 2019 and beyond. So the timing of those coming on impacts the capital cost, it impacts the production. But I wouldn't say that we see the first quarter declining. I think it's going to maintain or grow some and then we will go from there.

[Neal Dingmann:]

And the CapEx seem to be pretty well evenly spread then throughout the year?

[John Hart:]

Yes. I mean within a band, it's pretty evenly spread. The fourth quarter is a fair amount lower just because we have got some completions that the real completion dollars don't start to come in until early 2020 when that activity is and that's just the timing of some of these units across our portfolio. So first and second quarter are lower than they, all four quarters are lower than the fourth quarter of 2018.

[Neal Dingmann:]

Okay. And then just one last follow-up, if I could, just regarding rig allocation and overall activity. My question is regarding the Bakken. Obviously, the massive inventory you have there and just how great those wells continue to outperform. Your thoughts on just why just six rigs there versus what the 18 or 19 you were running at the MidCon?

[Jack Stark:]

We are comfortable with the six right now and we think it's a good balance with what we see as the takeaway capacity and our ability to go ahead and manage and grow our SpringBoard project. So we clearly have the ability to increase that. You could we were up to eight rigs at year-end. We can go right back to that when we choose to if the market would justify it and if it make sense for us. So it's always about a balance.

[Harold Hamm:]

Yes. And with our six rigs up there, it's unreal how fast these units are drilled and how much, how many wells that they go through at a year of time. So Gary?

[Gary Gould:]

So this is Gary Gould. And even though we are going down in rigs, we expect to drill more wells this coming year than last year. So it's really a matter of drilling efficiency in terms of that rig count.

[Neal Dingmann:]

Great details from all of you. Thank you.

[John Hart:]

Thanks Neal.

[Operator:]

And our next question comes from the line of Derrick Whitfield from Stifel. You may begin.

[Derrick Whitfield:]

Thanks. Good morning all.

[John Hart:]

Good morning

[Jack Stark:]

Good morning

[Derrick Whitfield:]

Regarding the inventory comments associated with your five year vision, would it be fair to say that well productivity and returns in years six through 10 or the following five years are not materially different than years one through five of the first five years?

[Jack Stark:]

Yes. I think that's a great comment there because when I was talking earlier about the blended inventory that we have when we get into this multizone full unit development, what you are doing is you are kind of perpetuating that type of return over a much longer period of time. And so we do see that second five years after this five years to look very similar in performance as to the first year as far as return are concerned.

[Derrick Whitfield:]

Very helpful. And then shifting over to the Bakken, could you speak to your appraisal initiatives for testing enhanced completions beyond the core fairway in 2019? And specifically, I am thinking of really testing your current design in northern Williams and Divide?

[Jack Stark:]

Yes. We have that in the Q. We have some testing going on and as we continue to step out with our optimized stimulations and you are right, we are stepping out north, south and west.

[Derrick Whitfield:]

Okay. Good. Thanks for the details guys.

[Jack Stark:]

Thank you.

[John Hart:]

Thank you.

[Operator:]

And our next question comes from the line of Paul Sankey from Mizuho. You may begin.

[Paul Sankey:]

Thank you. Good afternoon. I appreciate all your comments. If we take a further step back and look at Continental today against two years ago, four years ago, six years ago, would you say that you are very much now pursuing returns over growth and how your strategy has shifted? Thank you.

[Harold Hamm:]

Yes. Paul, I would be glad to do that. And we go through about four stages. We talked about leadership here and [indiscernible], each one of those basically deal with discovery, delineation, unit development testing and then get into full field development. And that's basically where we are at with the Bakken. We are also there with SCOOP and STACK. So that's the position that Continental is in. And you go through most of those first stages, you are dealing with trying to hold HBP acreage and with all those steps that I just talked about. And here we are in HBP position. We are developing these at very good rate of return unit wise across and field wide. So Continental is in a very good situation. Relative debt is low and we churn off a lot of free cash flow and contemplating paying a dividend. This has all written itself.

[Jack Stark:]

And Paul, the capital efficiencies that go along with being in this mode of development and when you get into this multizone full unit development mode, those efficiencies really start evolving. And a great case point is, we just started in SpringBoard drilling Springer wells in row one and our teams have already knocked down the cost, the complete well cost per well 10% after drilling the first row and they are looking at another 5% to 10% reduction ahead of us. And you have heard talk me previously about anywhere from $500,000 to $600,000 a well that our teams are targeting for further cost reductions down in our SCOOP project. All those things result from concentrated effort within unit development. And then on top of that, take SpringBoard, there you have got an oil gathering facility right in the center of this 73 square mile project. You have direct pipeline connectivity to refinery. You have got just a short distance by pipe to Cushing. And then we have based our own firm transportation on pipe that takes our gas right down to what we consider to be some premium markets down in Texas. And right now, on row one, about 100%, 95% of our oil and water are all piped. And row two and three that are under development right now are basically heading in the same direction. And so all of the completion fluid, all the water we have is being recycled through our own recycling facility, et cetera. So you get the point that the efficiencies are built really start being turned on and that's where it translates, not only do we get the reserves and the production, but we also get it at a very cost-effective process. And Gary?

[Paul Sankey:]

I appreciate these comments. Thank you. Sorry, was there someone else? Sorry.

[Gary Gould:]

So this is Gary Gould. I would like to add one more thing to Jack. Jack has talked a lot about our operational efficiencies. Earlier, Harold talked a lot about our five-year plans and how we have a history of meeting them over and over again. And I think one thing that's important to point out about this five-year plan is that it's very detailed by type curve area, by zone but it's based on efficiencies that we have already realized. And what you see with Continental is the ability to continue to improve efficiencies, whether it be on CapEx or completion designs as we go forward. And so this is a conservative look on a five-year plan in that it's based on what we have already witnessed to-date for our type curves and CapEx.

[Paul Sankey:]

Yes. But if I said that you should cut CapEx by 30%, what would be comment?

[Gary Gould:]

If I should cut CapEx by 30%?

[Paul Sankey:]

Yes.

[Harold Hamm:]

Well, we would have several come back from that. And first all, we have got people that suggest that up it to the limit of free cash flow. I think that it's a balance program, as John talked about. It's very important here. And certainly that resonates with us real well.

[John Hart:]

Let's say, if we cut by 30%, we are also still growing. That's still a number that's above our maintenance capital level for 2019 and would still be in a good shape. Not the same numbers, obviously, but we would be very strong relative to our industry.

[Paul Sankey:]

Sorry to go on but what's your perspective on Washington, DC right now? It feels like the big threat is Iran sanctions. But any further thoughts you have? Thank you.

[Harold Hamm:]

Well, I think that Iran sanctions will happen. This President is somebody that carries out what he says. And obviously, there were several things at work. Last time the President was there to grant those extensions and along the way, we witnessed what he did. But I think that's a big thing. I think he is a pro-business President and that bodes well for industry as well. He believes in America first and putting America first in energy is very important to him.

[Paul Sankey:]

Thank you Harold.

[Harold Hamm:]

Thank you.

[Operator:]

Thank you. And our next question comes from the line of Jeanine Wai from Barclays. You may begin.

[Jeanine Wai:]

Hi. Good afternoon everyone.

[John Hart:]

Good afternoon.

[Jeanine Wai:]

Hello. So I just wanted to follow-up on Brad's question. I was a little surprised that you included the Bakken in the blended lower RORs and I was kind of expecting that commentary to be more skewed towards the STACK and the SCOOP. If I am thinking about it right, the Bakken is a bit more of a mature play for Continental. So I was just wondering what's driving what sounds like a change in the development style, especially given that the 2018 program in the Bakken has an ROR of 125%. So is this more related to maybe any updated inventory assumptions you have in the Bakken? Or have you really improved the economics of the lower zones enough now that you are more willing to do a more wholesale development style versus being more selective? Just trying to see if I am thinking about this right.

[Harold Hamm:]

Basically, there is not change. It's the same development style as we have had up where when we developed units. Like Jack said, if you don't develop first and second Three Forks, basically you don't get it. And it's much too valuable to leave behind. And even at moderate prices of we are today, it still makes economics and while we own those pads, it makes a lot of sense to develop it.

[Jack Stark:]

Yes. And Jeanine, I would say, take a look at slide nine and as Harold said, there is no change. I used the Bakken as an example because people are most familiar with the Bakken. But you can see the performance that we are seeing in 2017 and 2018 and we don't expect to see different performance there.

[Jeanine Wai:]

Okay. Great. That's really helpful. Thanks. And then my second question is back to your prepared remarks on the five-year plan. You mentioned that the range of annual free cash flow is somewhere between $500 million and $1 billion, all on the same $60 WTI. So can you discuss what factors are driving the high end versus the low end of the range?

[John Hart:]

It's a larger production base as we grow through the cycle. I think we indicated it was $500 million to $1 billion plus. The average is obviously higher than that $700 million. $800 million range that Jack said. But if you think out to five-year and you just take the $325 million from the fourth quarter and tack on 12.5% a year, you are getting the company, to Harold's script comment, that's almost double the size of today. And then you factor back to that, I think it was first question we got on just the CapEx cadence to that five-year being from where we are at now up into the mid-$3 billion, you can extrapolate from that a significant amount of cash flow growth and an increasing amount of cash flow growth as you are going through the five-year horizon.

[Jeanine Wai:]

Okay. Great. Thank you for taking the my questions.

[Harold Hamm:]

Yes. Thank you.

[Operator:]

Thank you. And our next question comes from the line of Brian Singer from Goldman Sachs. You may begin.

[Brian Singer:]

Thank you. Good afternoon.

[John Hart:]

Hi Brian.

[Brian Singer:]

I was planning a question on slide five, which I guess it sounds like the bottom rate of the projected free cash flow point of slide five, the upper end of that range, maybe much higher relative to what's in there. Maybe you could just verify that. But I guess philosophically, you have a $55 and $60 case here. If commodity prices average below $60, let's say $55 just for the sake of it, how would you respond in the longer term? Would you anchor to more of the free cash flow number? Or would you anchor more to a growth CAGR?

[John Hart:]

Good question. First of all, on the chart, I think the chart is the low end of the range we talked about there and just taking that low-end out. So it's a very conservative look, I would say. That's probably something we need to update to be more reflective of what we are really seeing. And so I appreciate the comment there. That chart is overly conservative is the answer there. On your question on the $55, great question. I think we would see, in terms of usage of that cash, we would continue to pay down towards certainly the $4.2 billion range on total debt. That's approximately that with the callable bonds. So continuing to pay down debt. And then if it's in the $55 flat environment, we can execute fairly comfortably on our plans. It wouldn't get quite as much cash flow as compared to $60. That's us just math, but it gives us plenty to continue to put off a significant amount of free cash flow, achieve our debt targets and then have amounts left for a dividend. That's why we speak to dividends and sustainable type fashion down to as low as $40.

[Brian Singer:]

Okay. Great. Thank you. And then my follow-up goes back to a comment that you made earlier with regards to oil mix. And I think you said but it would be great if you can clarify that, over the next few years you expect your oil mix for the total company to rise. But I wasn't sure if I heard that right. But maybe you could talk about a little bit of the dynamic between production and the mix and production versus the mix and reserves and whether you see the oil mix which I think is lagging and reserves relative to production catching up over time or whether the oiliness of the producing base at some point starts to decline?

[John Hart:]

If you look at our year-end reserve reporting, you will see that our oil percentage went up this year by several percentage points. I think we still have some opportunities in that as we go forward. And even within our gas, there is a lot of condensate in there, a lot of NGLs. So if you look from a total liquids standpoint, today at 10% on it from a just a pure total liquids standpoint. In terms of the ratio, I gave the oil and gas volumes separately for 2019. We are going to continue doing that as we give the granular year-by-year guidance. As we move forward, we do see our oil ratio growing in our five-year horizon. Both volume sets will be growing, oil and gas. And certainly, where we are at right now, we have been very focused on the oil side.

[Brian Singer:]

Great. And thanks for that oil and gas breakout. I appreciate it.

[Operator:]

Thank you. And our next question comes from the line of Leo Mariani from KeyBanc. You may begin.

[Leo Mariani:]

Hi guys. I was hoping you could give me a little bit more clarity around your oil growth target this year. I know you guys were saying around 13% to 19% growth, I guess, relatively wide. What are sort of the key variables that kind of influence you guys to be closer to the low end versus the top end this year?

[John Hart:]

We deal with a lot of variables. For instance, in the Bakken, you have weather considerations that frankly that impact any of the 12 months of the year. So we always factor those types of scenarios. And we have got a lot of infrastructure coming in the basin. And so we factor in a bit of risking associated with the timing of that. Projects can move up or back a month on the infrastructure side. And that can impact production. So we factor that in. And then we factor our normal just overall production type risking in. So I think what you see there is we are somewhere in the midst of that on our set internal target and then we got a degree of risking and a degree of upside opportunity in there that kind of gives you some range.

[Leo Mariani:]

Okay. But that range is not really based on moving your spending around or increasing anything like that in 2019.

[John Hart:]

No. It's based on what we have deployed. I mean, there might be a little bit in there in terms of your moving spending around the timing of individual projects can impact the actual production in a period. If a project moves forward by a couple of months on one of these large units in any of our plays that can obviously benefit production for this year. So that type of movement is certainly considered in our range. So you look at the size of some of the things we have brought on the last few quarters, you can imagine. Well, if you have that two months sooner, that can have a material impact on the overall.

[Leo Mariani:]

Yes. Okay. No, that makes sense. And I guess you talked about some potential well cost reductions that you would like to achieve here in 2019. It sounds like a lot of that was more based on some new well design. I just wanted to kind of clarify. So you guys have not factored any of that, I guess, into the 2019 budget. And I am assuming that's not factored into the five-year outlook as well. I am just trying to get a sense if there's a service cost component to some of those well cost reductions or if that's more just efficiencies in well design this year?

[Pat Bent:]

Yes. This is Pat. And one of the things I would like to bring up is, the well cost reduction, those are a function of the technical and operational efficiency of our organization. So those are not price related. And so the teams have done a great job with respect to design work on our wellbore designs. And so in answer to your question, a portion of those costs are built-in. We previously referenced $1 million per well savings in our SCOOP, Woodford, Sycamore program based on a mono-bore design. And we have included that in the budget. We are anticipating an incremental. We have already realized in the second half of 2018 another $500,000 on that same well set that's not been built into our budget. In addition, in STACK, we are contemplating a new wellbore design. They will increase our rate of penetration, lower our tubular costs, et cetera. That could bring as much as $650,000 gross per well to the table. And so that's not contemplated in the budget as well. So a portion of it is and a portion of it isn't.

[Leo Mariani:]

Okay. That's very helpful color. And I guess just lastly on your fourth quarter Bakken wells. They looked materially stronger on 24-hour IP rates versus your third quarter levels and you have a pretty big sample size, I guess, with 52 operated wells this quarter. Just trying to get a sense, kind of what drove that heady increase there in production rates versus 3Q?

[Gary Gould:]

Yes. This is Gary Gould. And yes, it was a record quarter for us. If you look on slide nine, what you see is the 2018 average, I would tell you, the fourth quarter 2018 average is even above that. And then if you look at slide 10, you can see that we had four wells that hit our top 10 list just from this quarter and they continue to expand our core up in the Bakken area. When you talk about what things we are working on from a completion perspective, we continue to like multiple entry points as far as our per cluster spacing being around 30 feet. And what we are doing is, we are looking at limited entry perforating in order to go to larger stages but still have the same amount of production and same amount of contact points with the well.

[Leo Mariani:]

Okay. No, that's helpful. I was just trying to get a sense of whether or not that was maybe driven by moving activity kind of closer to the core? Or it is more just you guys getting better at drilling and completing these wells.

[Jack Stark:]

Well, I would say, as our guys are getting, all of our folks are getting better at it, I agree with that. On slide 10, the key point there and putting those on there, the spotting of wells is just to show it's a broad footprint where these results have been achieved. And so it's not like we just went and cherry picked a particular area.

[Leo Mariani:]

Okay. Great. Thanks guys.

[John Hart:]

Thank you.

[Jack Stark:]

Thanks Leo.

[Operator:]

Thank you. And I am showing no further questions at this time. I would like to turn the call back to Rory Sabino for closing remarks.

[Rory Sabino:]

Thank you very much for your time today and please reach out to the IR team with any further questions.

[Operator:]

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