Continental Resources, Inc.
Q4 2014 Earnings Call Transcript

Published: 25 Feb 2015

[Operator:]

Welcome to the Fourth Quarter and Year End 2014 Continental Resources, Inc. Earnings Conference Call. My name is Richard, and I'll be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I'll now turn the call over to John Kilgallon, Vice President of Investor Relations. Mr. Kilgallon, you may begin.

[John Kilgallon:]

Thank you, Richard, and good morning, and welcome to the Continental Resources Fourth Quarter and Year End 2014 Earnings Conference Call. Joining me today with prepared remarks is the Company's Founder, Chairman and Chief Executive Officer, Harold Hamm; our President and Chief Operating Officer Jack Stark; and our Senior Vice President and Chief Financial Officer and Treasurer John Hart. Also during the call this morning, joining us for Q&A will be Gary Gould, Senior Vice President of Operations and Jeff Hume; Vice Chairman of Strategic Initiatives among others. Let me remind you that today's call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ from those contained in our forward-looking statements. Please refer to the company's filings with the Securities and Exchange Commission for additional information concerning these statements and risk. Also in the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these non-GAAP measures to the general accepted accounting principles, please refer to the updated fourth quarter and full year summary presentation that was posted on our Web site at www.clr.com yesterday evening. With that, I will turn it over to Harold.

[Harold Hamm:]

Thanks, John and thank you all for joining us today everybody. I know the majority of the attention that would be to our 2015 plans and our ability to adjust and adapt to the current lower oil prices but there is several accomplishments I want to touch on first that are important to all of us that here at Continental and our shareholders. First, yet again in 2014 the company delivered solid production and proved reserve growth, growing production 28% and proved reserve 25%. I want to complement our entire team here in Continental for delivering big results this quarter. Along with continued growth we also made considerable progress in delineating our SCOOP Woodford play, which is finally getting reserved attention from numerous external analysts, investors and consultants due to its very strong returns. Also in 2014 we announced another SCOOP milestone, the second prolific producing formation SCOOP the Springer oil discovery. Before announcing this play, we captured the valuable core leasehold of basin at first mover advantage prices, we have successfully drilled over 30 Springer wells and the process of further delineating play now. SCOOP has matured from a very promising exploratory area to a standalone core asset nicely complimenting our viable Bakken asset. SCOOP accounts for approximately 21% of our total production up 0% just three years ago. We proved its validity as another growth platform driven by the basin with strong execution of our exploration and operations teams. Also, in 2014 we further delineated America's crude oil field the Bakken where production averages 85% light sleek crude. The balance is 15% natural gas with a high average Btu content of 14/50. With proved deliverability and multiple horizons and also applied advanced drilling and completion techniques to expand and increase historical EURs per well. Lastly we help thank our new pipeline infrastructure in the Bakken to increase takeaway capacity and provide fixed transportation rates which should lay long-term lower differential and higher realize process to the company. Our performance in 2014 demonstrates world class caliber, had both our teams and our assets. The operational innovations of our teams enhanced completions and artificial lift application as well as utilization of extended lateral sales help maximize recovery. Their talent, technical expertise and dedication help crack their completions code. The experience and knowledge we obtained in last year sets to stay for an even better 2015 has we got efficiencies throughout the system. As we move on to 2015, I want to compliment our industry for their prompt response to today's low oil price environment reducing 2015 CapEx on an average about 35% to 40% with over 50 billion in capital reductions announced so far. The industry wide the rig count has already dropped over 30% since year-end 2014 and is continuing to head lower. These actions will accelerate rebouncing of strong demand and facilitate recovery to more rational prices in the future. In the meantime with Continental we are focused on protecting our balance sheet and maintaining our financial strength. Our 2015 budget has been adjusted to target near term cash flow neutrality. We have plenty of liquidity and are well positioned to adapt to market conditions. A large percentage of our key assets are held by production with remainder having considerable term and/or protection by contractual provisions. So we can defer a significant amount of activity to await a better commodity price environment and lower oil field service cost. For example, in the Bakken we have deferred first quarter 2015 completions by 25% versus our previously planned levels of activity. We anticipate individual well returns will likely improve these oil field service cost in them. We also expect to achieve efficiency gains across the board that will pay dividends to years to come. Lastly, I'd like to mention enormous amount of work currently being done and support uplifting the 1970s press control era ban on crude oil exports from the United States. This is a good environment to make progress on this and I'm highly optimistic we will get there and make this happen. Recently, when asked about lifting this ban on Monday Oklahoma Governor Mary Fallin approved and said he was open to discussion. This could be accomplished by executives order and happen very quickly. Thank you for your time and interest in Continental. Now I'll turn the call over to Jack Stark.

[Jack Stark:]

Thanks, Harold and good morning everyone. Appreciate you being on the call with us today. As Harold mentioned 2014 was another solid year growth for us as we achieved record production and improved reserves. We also made great headway on several fronts. For starters SCOOP really proved itself as another major platform of growth for the company representing 21% of our fourth quarter production and 27% of our proved reserves at year-end 2014. During the fourth quarter SCOOP production averaged 40,400 barrels of oil equivalent a day up 70% of our fourth quarter 2013. The year-end 2014 SCOOP proved reserves stood at 370 million barrels of oil equivalent which preferred for our prospective is essentially equivalent to the company's proved reserves at year-end 2010. As announced we had some excellent Woodford and Springer completions in SCOOP during the fourth quarter. In the Woodford we had a record setting completion in the Oceana well located in Stevens county. The Oceana well floated a maximum 24-hour rate of 20.7 million cubic feet of gas equivalent from 9,200 foot lateral. Approximately 20 miles to the southeast, we completed the Cana well with a maximum 24-hour flow rate of 11 million cubic feet of gas a day and 518 barrels of oil per day from a 9500 foot Woodford lateral. In the Springer the Schoof and Martha Skid wells located in central Grady County produced at a maximum 24 hour rate of 1,465 barrels of oil equivalent per day and 935 barrels of oil equivalent a day respectively. Approximately 20 miles to the southeast the Lyle Land and length over the wells had maximum 24-hour flow rates of 1,135 barrels of oil equivalent per day and 885 barrels of oil equivalent per day respectively. All four wells were approximately 4500 foot laterals and a production averaged about 76% oil. During the year we also initiated four Woodford and two Springer density tests to accelerate our understanding and the full potential of SCOOP. Two of those pilots began producing recently specifically the Good Martin and the Hartley unit. The Good Martin unit was a Woodford oil window density test and included eight wells, spaced approximately 660 feet apart. These wells had an average lateral length of 6,775 feet and an average maximum 24 hour flow rate of 820 barrels of oil equivalent per day per well. These wells have been producing for approximately one month, so it's a bit early to say much except that their producing in line with offset producers and we're very pleased with the results. The other density tests at Hartley unit was a four well Springer oil window density test with three well spaced 1,055 feet apart and one well 2,110 feet from the nearest well to test the different inner well spacing. The four wells had an average lateral length of 4,605 feet and an average 24-hour maximum flow rate of 1,185 barrels of oil equivalent per well per day with 72% being oil. Again, the Hartley wells have been producing less than a month but we are encouraged with the early results. In the Bakken field we expanded technology once again during 2014 by testing various enhanced completion techniques to ensure we are maximizing recovery from the field. This included higher profit volumes as well as slickwater and hybrid techniques which combines slickwater and crosslink technologies. We found that the slickwater and hybrid completion techniques both delivered improved economics and recoveries in the central portion of yield particularly in Williams and McKenzie County. Today we've completed approximately 50 30-stage enhanced completions in Williams and McKenzie Counties utilizing slickwater and hybrid techniques. 36 of these wells have had over 90 days of production. The performance of these 36 wells and other interesting wells in the area continued to show production uplifts of approximately 30-45 % in the first 90 day rates with a corresponding 25% to 30% increase in EUR. We have also completed 56 40-stage enhanced completions across various portions of the field using slickwater and hybrid technologies. Only few of these wells have over 90 days of production so no conclusions have been drawn at this time. We'll continue to monitor the results from these 40-stage enhanced completions to see if the added investment is warranted. In the meantime we'll continue on with 30-stage enhanced completions as budgeted for 2015. So let's turn to 2015. As previously announced we reduced our 2015 CapEx by approximately 40% to $2.7 billion starting cash flow neutrality by midyear 2015. This reduction demonstrates the operational flexibility and optionality we have to adjust the market conditions, thanks to the high quality of our world class assets in the Bakken and SCOOP. This budget assumes a decrease 15% in cost on average during the year and we have seen about a 10% reduction in service cost so far and expect to see at least 15% cost-savings by midyear. As budgeted we are in process of reducing our operating rig count from 50 at year-end 2014 to an average of 31 four 2015. We currently have 36 operating rigs drilling including 12 in the Bakken, 20 in SCOOP and four in northwest Cana. For the year we plan to average 11 rigs in the Bakken, for rigs in northwest Cana and 16 rigs in SCOOP. Our 16 SCOOP rigs will vary between 10 to 13 rigs in the Woodford and 3 to 6 in the Springer. In the Bakken our drilling was concentrated in the core of the field targeting an average EUR of 800 MBOE equivalent per well. Approximately 60% of our drilling in the Bakken, we concentrated in Williams and McKenzie County where enhanced completions are delivering improved results. The remaining 40% will be concentrated in Dunn and Montréal Counties where we're expanding our footprint of enhanced completion techniques. In SCOOP our drilling where focused on the combination of infield, step-out and density locations to further define the potential of this growing asset. In northwest Cana we'll be focusing on development and step-out drilling as well. During 2015 we also plan to reduce the number of operated completion crews from 14, year-end 2014 to an average of 8 for 2015. By doing so we will minimize the volumes produced at today's oil prices and enable us to benefit from the oil markets contango. In the Bakken we had 10 crews running at year end 2014 added to be down to four crews in early March. In SCOOP and northwest Cana we are currently operating for crews and expect to keep 2 to 4 crews running through year-end. Now I should add that we're planning to drill our first well in the second play during 2015 as well. Although we have not actively pursued this plane to this point, we've been monitoring it very closely. In similar act we recently announced several song completions from wells near an adjacent to our acreage in stack. Those are great news for Continental and our shareholders as we have what appears to be another significant opportunity of growth and margin underneath our acreage. So we currently own about 103,000 net acres in Stack and approximately 60% of this is held by production. So, before I turn it over to John Hart our CFO, I want to thank all of our employees for the hard work and leadership they put into navigating our company to the market changes we have been experiencing recently. It's a true testament to the quality and the dedication and commitment of our employees and our shareholders can be sure that our assets are in good hands. With that I'll turn it over to John.

[John Hart:]

Thank you, Jack. And good morning to everyone on the call. As Harold and Jack both mentioned, 2014 was an excellent year for us on many fronts, with year-over-year production growth of 28% and-full year EBITDAX of almost 3.8 billion which was 33% higher than the full-year 2013. Net income for full-year 2014 was $977 million. Our fourth quarter results continue to reflect our commitment to deriving value from our assets. Our fourth quarter EBITDAX increased 66% over the prior-year, coming in at 1.2 billion. Net income for the fourth quarter was 114 million. This includes 348 million in pretax proceeds from liquidation of hedges that had original maturities in 2015 and 2016. An additional 85 million was recognized in the fourth quarter for early settlement at November and December 2014 contracts. And then we had normal settlements for October in the oil and for our natural gas as well. Fourth-quarter net income was also impacted by impairment charges of 394 million as discussed in our release. In addition for fourth quarter 2014 our operating cost where in line or better than guidance with the least operating expense of $5.31 per BOE, DD&A at $22.39 and cash G&A of two dollars per BOE. This is a strong affirmation to our focus on managing cost. Although our full-year oil and gas differentials were within our annual guidance at a $10.81 differential growth and a positive $1.02 differential for natural gas, the dramatic softening in NGL process produced on natural gas differential to a positive $0.35 for the fourth quarter. We anticipate this softened price for NGL we continue in the near term as it correlates to the price of oil. As a result we have taken a conservative stance and reduced our 2015 natural gas differential guidance to flat to a negative $0.50. We do expect less volatility in the oil basis differentials for the Bakken in 2015 as sizable new interstate pipeline capacity and a new 20,000 per day barrel refinery in Dickinson North Dakota becomes available in the spring. As Jack mentioned, as we move forward into 2015 we are taking a proactive approach in adjusting our plans as commodity process have fallen in over the past few months. It has been and continues to be our intention to maintain our strong balance sheet and financial facility regardless of the pricing environment. Even though we have recently reduced our CapEx guidance by approximately 40%, our production guidance still remains at a strong 16% to 20% fueled by momentum exiting 2014. We expect 2015 production to rise through midyear and level off in the second half of the year. This equates to single-digit growth in our year-over-year exit rate. Looking forward to 2016, we expect we can maintain a growth rate in the mid-single digits with flat CapEx at 2.7 billion, so in a sense maintenance CapEx. Our deepened diverse inventory provides us with a lot of optionality when designing our development plans. For 2015 our current 2.7 billion CapEx plan was developed with a focus on aligning CapEx to be near discretionary cash flow by midyear 2015. At the $60 benchmark WTI we would expect to be cash flow neutral by midyear. At $50 the outspend in the back half of the year would be moderate and around 200 million to 250 million. Additionally, due to a slowdown of completions we are currently under-budget on CapEx yet within our production guidance for the year. We continue to have one of the strongest cash margins and recycle ratios in the industry. Our cash margin for the fourth quarter was $35.24 per BOE or 69% of our realized price of $51.11. For full-year 2014 our cash margin was $48.86 or 73% of our realized price of$66.53. These strong cash margins are underpinned by a low cash operating cost which runs approximately $16 to $18 per BOE depending on commodity prices. Our total cash cost including interest was a very respectable $7.67 per BOE in 2014. And even though realize prices have been coming down, so had the cash cost. In particular production severance tax directly tied to the net realized price received and scales up and down with commodity prices. Therefore you can expect to see our cash cost per BOE decline allowing us to maintain a strong cash margin. Our cash margins combined with our low-volume F&D per BOE generate an industry-leading leverage recycle ratio of almost 4 times reflecting just how efficient we are recycling our cash and realized the returns on our invested capital. On the financing friend we continue to have ample liquidity and no near-term debt maturities, allowing us to control how we deploy capital in 2015 and preserve our ability to grow at an accelerated pace when commodity prices increase. To further enhance our liquidity and to be prudent during this price environment, we recently increased the commitments under our unsecured credit facility by 750 million to a total of 2.5 billion and currently have availability of approximately 1.9 billion under that facility. We have had several questions in this regard, so let me clarify that commitments under our unsecured credit facility are not dependent on a borrowing base calculation that is subject to periodic redetermination based on changes in commodity prices and reserves. We have only one covenant in our credit facility involving of financial ratio. It requires a consolidated net debt to total capital utilization ratio be no greater than 0.65 to 1. We continue to be comfortably under this limit and expect to remain so. You may have seen that Standard & Poor has recently issued a report of their review of 23 oil and gas E&P companies. Of those 23 companies, Continental was the only company whose rating and outlook were reaffirmed. This is the testament to the financial strength of our company and we believe our proactive response to the downturn in commodity prices has been well-received and provides assurance we will continue to make the right moves to maintain our strong financial position. We remain committed to maintaining our investment grade rating. Again let's thank you for joining us on the call today. Now we will gladly take any questions you may have. Operator, please provide instructions to ask a question, thank you.

[Operator:]

[Operator Instructions] Our first question on the line comes from Joe Allman from JP Morgan, please go ahead.

[Joe Allman:]

Jack, a quick question for you and then I'll go to a different question. So you talked about the SCOOP and the Springer down spacing test. Did you see any communication, I know it's early days, but did you see any communication and I guess, if you don't see any communication, I guess the implication will be that it might need a down spacing even further.

[Jack Stark:]

It's a great question. That's what we're trying to demonstrate here. Joe, we've only got 30 days of production max, so it's just way too early for any of that. At this point we have seen some of the tests out here that some other operators have done, and I think it's clear that we can, 6 to 7 wells in the Woodford are pretty much given in my mind right now, depending on the thickness in the area that you're in. But that seems reasonable and for the Springer, we're just blazing trail here. We are the first to doing the work there, not very pleased with the results.

[Joe Allman:]

Okay, very helpful Jack. And then a question about the transportation, and it's regarding transportation the Bakken -- from the Bakken and from the Anadarko basin as well; can you talk about any changes that you're undergoing recently with the wider Brent WTI differentials? And could you just give us thoughts about the potential for Cushing and the Gulf Coast, what could happen there with the current above-average storage?

[Jeff Hume:]

Joe, this is Jeff. The transportation out of the Bakken, we have always maintained a good balanced approach or a basket approach where we can move wells either via rail to the East Coast markets in this wider arm really allows for that to take place, or there's a strong appetite for the production in both East and West coast via rail, so that really helps those refiners show up. We also have good pipeline infrastructure now. It's improved with the renewed -- now Kinder Morgan pipeline tied to Pony Express and that expansion coming online. So we are able to move from market to market and take advantage of wherever that are, or whether it's getting water like it is today or it's no early in the months. So we can move from market to market on that. Into SCOOP, we are close to Cushing, we are getting more pipeline access from the field to Cushing and its growing. Will have better connectivity by midyear, probably early May, We'll have better connectivity. We applied to Cushing. The markets are really strong. We need to realize that both of these are light sweet crude oils, not blended crude oil just meets domestic light sweet spec. And so they're doubled up pretty quick. All the refiners want this oil, so we have a strong desire for this oil, and not having any problem at all marketing it. To answer the storage at Cushing, it is growing, a lot it is being fed just by the con tango itself. There's several dollars per barrel per month that can be made, rolling the barrels, so you have folks that own the storage over there that have you at least are taking advantage on that, buying a barrel and rolling it out several months, so you have a con tango play going on. We are also suffering a little bit of reduction in refinery from turnarounds and the striker is affecting a little bit, not much but some of that from the strike. That will be going away. We have a very strong crack spread right now. Its $20-$30, West Coast is $30, Midwest and Gulf is over $20. And so you're seeing the refiners as they come out of turnaround of spring maintenance. They're going to be cranking up pretty hard. So I think you'll see the amount of oil going into storage taper off pretty quickly in the next 3 to 4 weeks.

[Operator:]

Our next question in the line comes from Doug Leggate from Bank of America Merrill Lynch, please go ahead.

[Doug Leggate:]

Jack, I wonder if I could pick up on your commentary about the success of this slickwater hybrid completions in the Bakken, in the core of the Bakken in particular, and how to that translates to the 800,000 barrel take for your high-graded portfolio this year? I'm just wondering what are you assuming in terms of the uplift in your 800 average versus what's actually happening? I'm just trying to understand why you're not finishing up by 800 take curve to the high-grade program, if you could help us understand that please?

[Jack Stark:]

Sure Doug. We included a 25% to 30% uplift in our EUR estimates in that 800 MBOU number and so it's built in and that's because our inventory. We get about 60% of our inventory can be drilled in the Williamson McKinsey County area where we are seeing just repetitive results and we're really pleased with what we're seeing in there and we expect to see that down in Dunn and Montreal counties as well, and we are in process of testing that as we speak. You know as I've said before, we've got -- we're experimenting and we're testing this technology and, you know, it continues to deliver results we are expecting in here. So it's still early, but anyways we like what we see.

[Doug Leggate:]

Jack, maybe I can try the question little differently, because what I'm trying to understand is what proportion of your drilling inventory this year are the completion inventory, I guess the better way to put it, is going to be the hybrid slickwater, and how would you expect -- assuming those successful how would you expect that proportion to change over time is really what I'm trying to get. In other words why aren’t you doing more of it?

[Harold Hamm:]

Well Gary, do you want to touch on that?

[Gary Gould:]

You bet. We're very impressed with the results that we have so far. So to answer your question, almost 100% of our completions this year will be enhanced completions with hybrid or slickwater.

[Doug Leggate:]

And that these units are 100%?

[Gary Gould:]

Yes.

[Doug Leggate:]

Thank you. My follow up, I got a bunch of follow ups but I am going only take my second one. So it’s really quick one. Can you explain foreign exchange charge, I guess in the K, there are some mention of exploration in Canada, can you tell us a little bit about what you're doing, what’s the plan is and how we should think about that perhaps in a better oil place environment. Thanks.

[John Kilgallon:]

So if you look back in prior years, it has been a few years but you have seeing some Canadian charges up there before, we add up there on the border in North Dakota. So at time we have tested exploration concepts across area and just some miscellaneous charges associated with some different places we have looked at.

[Operator:]

Thank you. Our next question in the line comes from Subash Chandra from Guggenheim. Please go ahead.

[Subash Chandra:]

Could you review and perhaps I just forget this but the SCOOP wells, how they are being completed or they sort of standard or enhance completion and those in field test – I think you guys have been really good at keeping data apples to apples with those also standard and what that could mean for enhanced completions in this SCOOP and ultimately stack area going forward.

[John Kilgallon:]

In general, the types of completion we put forward there in our SCOOP play are already enhanced hybrid and slick water types designs. And we have taken our learnings from play such as the Bakken and we apply them very quickly in the Woodford. And so we believe we're compared to apples to apples when we are looking at our density test down there.

[Subash Chandra:]

Okay, in terms of propane intensity same enhanced?

[John Kilgallon:]

Same levels of profits.

[Subash Chandra:]

Okay and then my follow up is a very high-grade, I guess like a better term of the 800 barrels of oil, are you sort of, going back to the distant pads and new pads what sort of combination is that and I guess what I am – the question I am asking is frac protect and if it is on existing pads, how you go about frac protecting, is that a bigger issue going forward?

[John Kilgallon:]

When you frac protect, you mean protect the current wells that are already there?

[Subash Chandra:]

Yes, correct.

[John Kilgallon:]

Okay. As we continue to develop the field, we will more and more begin developing areas that already have existing wells in place. When we go in a frac, there are times where we will shut in nearby offset wells to help protect, the frac communication that we see earlier on which is generally just the water and is for a short period of time. However, we’ve got all that built into the way we forecast or models and we expect that the sand and propend does not travel far enough to interfere with offset wells. And so this is why we expect that that type of results were forecasted in 100,000 BOEs for an EUR.

[Subash Chandra:]

Okay, I will put a different way. When you go back to perhaps a wider programming on a price recovery, do you think it will be easier to sort of coax production growth than it is when you have to worry about shouting a nearby producers?

[John Kilgallon:]

When you are standing in the field?

[Subash Chandra:]

Yes, let’s say we are in a $70 price environment, you go back to building new pads and sort of expansion works that you are doing in the past, would be easier to derive production well.

[John Kilgallon:]

When you're expanding out into new areas, you don't have that same type of operational performance.

[Subash Chandra:]

Okay so that will make sense. Alright, thank you.

[Operator:]

Our next question on line comes from Brian Singer from Goldman Sachs. Please go ahead.

[Brian Singer:]

Can you talk to how your oil outlook and actual prices dovetail into, how you think about your completion backlog and capital budget? It was with oil price or how much more would cost up to fall for you to add or subtract from your activity levels and can you just talk about flow of your backlog.

[Harold Hamm:]

We have seen that of course from 14 to about 50 bucks. We see in the future here, recoveries you know $50 to $70 certainly would – we start picking it up and then $70 environment and completing more of these wells that we are deferring.

[John Kilgallon:]

Brian just to your question, for economic sense, no, a $5 change in the commodity price pays for you to differ for several months I mean that just a PV calculation on that and when you look to the con tango nature of the market we have got as of this morning, I think prior to December it was $8 or $9 difference. So you have got that cross difference and you factored that in coupled with what we are seeing in cost reductions, pushing those out for a few months absolutely make sense and we have optionality to do it further do more or less as we see fit in those environment but the current environment we see a positive rate of return impact from doing that.

[Brian Singer:]

There is another interesting point I want to, as this may not happen but theoretically if the backend occur would it come down to take that con tango to front end or not to fall from here, would that actually lead you to increase here to reduce your completion backlog?

[John Kilgallon:]

Potentially but we still think we are going to see capital reductions throughout the year and so we are seeing 10% so far, we expect more than 15%, close to the 20% or even more in the second half of the year and so that by itself also helps pay for delaying some of our completion likes we are doing in the Bakken.

[Brian Singer:]

And last one from me, based on the based on the improved well performance that you’ve talked about here, can you just talk to what are your prioritization would be between Bakken SCOOP Springer, i.e. environment where you do want to bring rigs back on would you bring them on first?

[John Kilgallon:]

We have got a lot of optionality with our inventory. We’ve just got such a great inventory in both of these plays that – for us there's just a lot of variables that would be out there for us to consider and so the good news is that we can mix and match our inventory in the rate to return to basically matching the environment and that’s what we have done right now. And so our mix I think we are going to continue to keep a mix, it’s very similar to where that right now. I don't see why we are rally changing it and we always have to depend on gas prices going to be versus oil prices and right now it seems likes oil prices, I would expect that they are going to be higher here in the latter half of the year.

[Operator:]

Thank you. Our next question of line comes from Mr. Mike Kelly from Global Hunter Securities. Please go ahead.

[Michael Kelly:]

Looking at the -- I am just going back and referring your Analyst Day slides and looking at your Woodford position, I think the time you guys have deemed about 45% of it de-risked and it looks like you drilled some pretty solid step out wells going to the south here this quarter, just wondering what that does for your thoughts on de-risk number and then any thoughts on how that maybe changed your thoughts on various windows of the play too?

[Jack Stark:]

I would say that we are 40% right, as what you said we had at Investor Day and the step also we have done as you know we have been stepped out at least 20 miles of the south east. So we have significantly expanded our de-risk position in this play and the results that we are seeing as just as you have seen in some of our report, they are just exceptional. I don’t know its an estimate right now, I would say, may be we are may be two-thirds de-risking here and you also have to throw in the springer there because it substantially de-risk because it’s just all the Woodford drilling and the test we are doing to this point. So Woodford, may be two-thirds, Springer is probably 75% I mean it’s really play that compounds on itself because of where the wells are being drilled.

[Michael Kelly:]

Great and all upon that, there is a lot going on in the mid-comp between the Springer and Woodford, Cana now stacked too. What in your opinion is probably the most incremental test or program that we should look for data that helps and approve out for the delineate the area in the midcon?

[John Kilgallon:]

I was going to say we are basically in all three of these I mean obviously Woodford what we have seen down in SCOOP, Woodford looks excellent you can see our results just continue to deliver Springer. It’s probably the best way to return out there from everything we see and we have not been active in stack, we have been watching it very closely and as said in the script here we have seen Cimarex come out with some announcements of several of very strong wells up there and those wells are drilled adjacent to and in and most acreage all throughout the stack play and we have got 103,000 that acreages up there. So which one of these rises to the top, I tell you what they are all looking really good but Springer to me is the probably the top but fact is that they are all delivering great way to return by look of it.

[Michael Kelly:]

Timing on that stack test?

[John Kilgallon:]

I don’t know probably first half of the year.

[Operator:]

Our next question on line comes from Leo P. Mariani from RBC Capital Markets. Please go ahead.

[Leo Mariani:]

Obviously you spoke about, starting to increase activity, we get back $70 WTI, just want to get a sense is that capital primarily go to Bakken at that point and if we do get at 70, would you guys consider hedging the well again?

[Harold Hamm:]

No, we would not be hedging at 70. So we expect price to do continually recover that here in the future. So we wouldn’t be hedging at that level. I think as far as activity goes, basically we would have a balanced approach to all of these price and we are looking at each one of them individually, as it compares to our entire inventory so I think you will see activity increase in all of them.

[Leo Mariani:]

Okay and I guess in terms of CapEx this year, you guys talked about being balanced as we get to mid-year, I guess that probably implies you potentially may have less CapEx in the second half versus the first half of ’15, could you guys kind of help us with that how that should be split out during the year.

[John Kilgallon:]

Absolutely. We come into the—we are down about I think 34, 35 rigs now we average little bit lighter than that as we go through the year all those numbers are in the detail but we came in with 50. So you see the front half is probably, I don’t have it right in front of me, it’s about two-thirds, I think of the total for the year, in terms of dollars so it does back off dramatically as we go through the year. The other thing that comes in there is we are projecting higher cost savings in the back half of the year than certainly what we have entered the year with or the 15% is an average for the full year, so that denotes that the back-half of the year as Garry said earlier 20% or more.

[Leo Mariani:]

Okay that’s helpful and I guess just looking at your program for this year in the Bakken and you guys are targeting 800 MBoe-EQ, I think the previous numbers you guys have turned out was like 775, is that number just gone up because you are seeing better well performance thus far?

[John Kilgallon:]

We had it 700 actually for our budget that we had previously to the 2.7 and that increase that you have seen is just the result of us continuing to high grade our inventory. So we can continue to step that up but this is a good blend that we feel we can get a lot of things done and the average of that blended in 800 MBoe-Equivalent.

[Operator:]

Our next question in line comes from Paul Grigel from Macquarie. Please go ahead.

[Paul Grigel:]

On the SCOOP and the Springer as well, when you focus on HPB requirements over the coming years here, could you just talk on how much you have, held by production now and then what the time horizon is on the areas that aren’t held at this point in time.

[John Kilgallon:]

Yes we have approximately 35% of HPB at this point in time. We look at this every day. Our drilling programs are designed to drill, the optimal locations while maximizing our HPB leasehold. We have got a lot of, as Harold said, contractual provisions in our leases that will give us a top lease protection and even automatic renewals, we have got a lot of term left on and the majority of our leases, its not that we are concerned about, it’s we keep up with everyday.

[Paul Grigel:]

When you say lots of term, could you put a number to that?

[John Kilgallon:]

Our leases from the onset are three year terms sometimes, lot of times with the three-year kickers. We have two to three years probably 60% to 70% two to three-year term remaining.

[Paul Grigel:]

Okay and then sticking with the SCOOP, you guys touched on a little bit on the oil takeaway capacity that is coming online. Could you talk on the midstream on the gas and processing front on any requirements that you need there or as you kind of continue to grow production what needs to be built out over time or there is enough capacity already?

[Jack Stark:]

There is good capacity on the plants, the midstream providers are staying ahead of us on the plant end of it. We work real well with them in both the Bakken and the midcontinent. So they are staying ahead of us. Takeaway capacity for residue and liquids is good in both areas for now. Eventually as we continue to grow in southern Oklahoma, there will be additional pipes built out of there. Quite a few folks have proposed lines over the past year, and as we see prices firm out, I think you'll see some projects come to the forefront. But over the next couple of years we are in pretty good shape right now.

[Operator:]

Our next question on the line comes from Dan Guffey from Stifel, please go ahead.

[Dan Guffey:]

You have a significant runway of undeveloped acreage and locations, but I'm curious are you seeing any opportunities and do you guys have any desire to add acreage in the SCOOP stack or Bakken, please?

[Jack Stark:]

Yes, sure, we continually evaluate our opportunities. We haven’t really slowed down from an acquisition or a leasing standpoint in any of our plays at this time. And we are planning to negotiate prices in line with the market.

[Dan Guffey:]

Okay, and then you talked about the success you had in slickwater and the hybrid fracs over in Williams County. As you move east into Dunn and Montréal counties, are you doing anything different or are you trying anything new as you move east?

[Jack Stark:]

Not as really particularly, just because we're moving east, we're testing the same type of designs everywhere and seeing if they are successful as we're seeing in McKenzie County and Williams County we will continue to expand. One thing we have mentioned earlier, we do have some 40-stage test that we completed late last year as well as early this year. We have a few more of those to test and we will watch that as we see 90 days of production or so in making an evaluation on that. But right now we are very pleased with our 30-stage results and are just looking to expand that.

[Dan Guffey:]

Okay, great. And apologize if I missed this. In terms of spacing with the upsized fracs, what are you thing in your opinion the ultimate development just in the Bakken, how many wells per unit you think is appropriate using these upsized fracs?

[Jack Stark:]

It's a good question, and we're going to be monitoring that to see. It would be great if we could actually reduce the number of wells because of the upsized fracs. But at this point we see a lot of -- our evidence really points to eight wells per unit in the middle Bakken and a minimum of four and up to eight in the Three Forks. And so nothing has really changed from that front. But you're exactly right. These upsized things could help us maybe reduce some of the cost to recover these wells.

[Operator:]

Our next question in the line comes from Andrew Coleman from Raymond James. Please go ahead.

[Andrew Coleman:]

The first question I had was, can you just run through the base decline for SCOOP and Bakken as we are looking at forecast in the PEPs here?

[John Hart:]

Yes, I can address that. Our overall base decline is in the mid-30%, so around 35% to 36% for the company. And so it's similar to lots of other plays, whenever you're in these unconventional plays there is an initial steep drop-off, but that's just the first year. After that it climbs out to a 20% in second year and about 15% the third year. And so that's about where that lies and with our activity of what we are investing right now at about $2.7 billion like to as discussed earlier, we are in a great position to maintain and even grow or production a little bit as we continue to invest in that level.

[Andrew Coleman:]

Looking at 150 million of other spend, is there any facilities optimization in that bucket, and I guess if so, could you give me a feel for how much of that is water handling, expansion or gas handling expansion?

[John Hart:]

For that those capital expenditures, a significant portion of it is for water handling. We have got some projects and yes, we are trying to recycle some water, saves us cost. If we can keep water that we've already transported to the area and recycle it. It’s a benefit for us on the capital and the expense side and we have some of those projects going in on in the south and then in the north we've also got some water inland type investments. But again they're a very good investment that payoff because they reduce our capital on wells going forward as well as our LOE expense thereafter.

[Andrew Coleman:]

And what's the average water cut up in the Bakken at this point.

[John Hart:]

Well, that’s a little -- I don’t have that number directly with me. But yes the water obviously comes on high, because of our initial fracs and then declines off over time and then there is variability throughout the play as far as natural saturations within the Bakken, so there is just variations of water cut throughout the play.

[Andrew Coleman:]

Okay. And do you foresee I guess as you get through the year with the slow down on activity and the deferred completions that you have excess water handling capacity or are we up against -- you know kind of with all the growth up in the play that it will be still against facility kind of limits there as we go through the year. We don’t see any facility restrains on our development.

[Operator:]

Thank you. Our next question online comes from Brian Corales from Howard Weil. Please go ahead.

[Brian Corales:]

Regarding the SCOOP Springer play it looks like the wells -- at least that you're putting in the re-lease much oiler than described at your analyst day, is that -- does it vary tremendously through the play or is it becoming more oily than you thought?

[Harold Hamm:]

No those wells were drilled right in and amongst the -- really at similar core, earlier drilling and the variability's just -- I don’t know that they're that different. I think we are seeing somewhere in the range of anywhere from 70% to maybe 75% oil and so it varies. But no, there's nothing right now that I could point to it that says -- going to very dramatically we do see that as this gets deeper it could transition into some acreage that we have divest here. We got about 77,000 acres out there that we think is maybe more in a gas maybe gascon I would say. But at this point where we're drilling it -- it all should be just about the same.

[Brian Corales:]

And then just another takeaway question on the Bakken, I guess, putting more oil into pipe or should we see -- where do you all think the differentials are going to over the next couple of years?

[Jack Stark:]

We've got our guidance for the company balance in the $7-$10 range for the year and that’s a combination of the Bakken the midcontinent the SCOOP barrels. Obviously we have a lower differential for SCOOP because we are concentrated at Cushing, and we'll continue to see -- I think improvement down into that. I think that $7-$8 range in the long-term is probably something we can look at and hold on to.

[Operator:]

Our next question on line comes from Marshall Carver from Heikkinen Energy. Please go ahead.

[Marshall Carver:]

Regarding your building and completions backlog, how does that factor into your comments around 2016 potential growth -- your comments on being able to grow on a single digit on flat CapEx. Does that assume a higher level of completions in '16, or flat or down versus the '15?

[Jack Stark:]

I recognize 20 flat CapEx year-over-year doesn’t mean the same level of activity because we've have had significantly lower service cost going into next year and depending on where prices stay it may continue to decline further. So you actually have a little big higher activity level. We will introduce our wells waiting completion at the end of '14 going into the end '15 probably about a third. Each completion crew gets through about 3-4 wells in the Bakken. So you actually see even with lower completion, you'll see that comes down as we go through the balance of the year. And that will provide you some higher PDP going into next year, but you'll get a little bit higher activity level also just because of the service cost reduction. So, all of that's factored in and we got a lot of inventory and a lot of optionality on where we drill and how we do it. So we can continue to generate good growth.

[Operator:]

Our next question on line comes from Noel Parks from Ladenburg Thalmann. Please go ahead.

[Noel Parks:]

Just a couple of things; do you have any update on the extended lateral tests you are doing in the Springer. I think you went up to 75,000 feet and you also stated some EUR and cost expectations. Do you have an update on those?

[Jack Stark:]

I've got an update on the first couple that we've done in the Springer. We've got one down that has lateral length of about 6,600 feet and then we are still drilling our second one and it has a potential lateral length of about 7,500 feet. So that’s where we are on those and provide updates on those future quarters. I would say one more thing -- one more thing would be that on the great efficiencies that we're working on, is to drill longer lateral lengths this year compared to last year in both the Woodford and the Springer play. So in the Springer last year all our wells were one mile laterals. This year we plan for roughly about half of them to be extended laterals. And then for the Woodford last year about 50% of our wells were extended laterals and this year we plan for about 85% of them to be extended laterals. So, that’s a very important efficiency for us this year.

[Harold Hamm:]

That also speaks to our ability to HBP acreage, which was questioned earlier.

[Noel Parks:]

And also in the 10K and the acreage tables, just sort of updating the acreage count by region. Welcome any general comments you have but a couple of things in particular I noticed is that the expirations in the sort of other category in the south coming this 2015 seem to be go up a lot about [indiscernible] and expiring in 2015 if not held, first is about 65,000 for that category in 15 last year. And also just a couple of the categories like for example Texas and Wyoming counts noncore counts also I think went up. So could you just talk a little bit about what those areas are?

[Jack Stark:]

Yes. Well, we -- you know we are an exploration company and we various projects around the country and not all of them work and so in the end I think maybe you're saying some of that.

[Noel Parks:]

Okay the Texas and Wyoming are those sort of in the rear-view mirror or things still maybe -- might be work on anything?.

[Jack Stark:]

You know we are always working on things, you don’t know, you know us, and so we've got our exploration footprint all across the country and so if one project didn’t quite work out we've got plenty other that are in the queue, so in the end we don’t exclude any state or any area.

[Noel Parks:]

Okay fair enough. And just one clarification I'd like to get on the guidance. The LOE guidance for example on unit basis hasn’t really changed since the analyst day and of course, we've seen the CapEx change a bit. But for the service cost cut expectations that you have; are those fully baked into the CapEx and the production guidance you have for the year or have you been a little more conservative as far as not necessarily counting much better service cost later in the year? I'm just trying to get a feel of that, as I was trying to reconcile it back to the free cash flow number you are looking at.

[John Hart:]

Several questions there. On pure debit, CapEx and associated service costs that goes with that. We factored in a scale where it's increasing as we go through the year. So the first quarter is lower as Gary said. He has achieved about 10% so far. He is ahead of budget on that. The average for the year is 15%, exiting the year is 20-25% by that time. So it’s a sliding scale. I'll tell you where we are going after service cost and efficiencies as quickly as we can while balancing our ongoing activities. Lease operating expense has a number of variables in there. We actually came in a little bit better than guidance for '14. And we kept the guidance the same. There are a lot of things that go in there like weather conditions in North Dakota, snow removal, road conditions in the spring. Those can impact that. The level of expense work hours planned and whether you do them in the timing of when you do them. There is a lot of variables, so we kept our guidance fairly flat and but we are pleased that the teams have done better than that. And as we go through the year we will continue to monitor that on, at least operating expense.

[Jack Stark:]

We appreciate the questions. This concludes -- we've gone past our hour of time that we were allowed for the call. So in respect to others that are reporting today we're going to cut it off here. If you do have follow-up we're certainly happy to go through those questions you might have. Thank you for joining us.

[Operator:]

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.