Continental Resources, Inc.
Q1 2015 Earnings Call Transcript

Published: 7 May 2015

[Operator:]

Welcome to the First Quarter 2015 Continental Resources, Inc. Earnings Conference Call. My name is Brandon, and I'll be your conference operator. [Operator Instructions] Please note that this conference is being recorded. And I will now turn it over to Mr. Warren Henry. You may begin, sir.

[J. Warren Henry:]

Brandon, thank you. I'd like to welcome everyone to the Continental Resources First Quarter 2015 Earnings Conference Call. Joining me today with prepared remarks are Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President and Chief Operating Officer; and John Hart, Senior Vice President, Chief Financial Officer and Treasurer. Also during the call this morning, joining us for Q&A will be Jeff Hume, Vice Chairman of Strategic Initiatives; Gary Gould, Senior Vice President of Operations; Steve Owen, Senior Vice President of Land; José Bayardo, Senior Vice President of Resource and Business Development; and Glen Brown, Senior Vice President, Exploration. 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 SEC for additional information concerning these statements and risks. Also on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these non-GAAP measures, please -- to generally accepted accounting principles, please refer to the updated summary presentation that is posted on our website at www.clr.com. With that, I'll turn the call over to Harold.

[Harold G. Hamm:]

Thanks, Warren. I appreciate everyone joining us on the call this morning. We are living today in historic times as world markets are recalibrating in the face of North American energy renaissance as demand expands to equal supply. Continental has been a leader in this renaissance. I'm pleased to tell you that we have adjusted to this new market condition and we are well positioned for success in this environment. Continental's high-quality assets and our financial and operational strength provide the foundation from which we will continue to grow shareholder value in the future. I'm particularly proud of Continental employees and their response to the challenges of the past 6 months, significantly reducing operating costs and creating an even more efficient and productive organization. Our first quarter performance is a perfect demonstration of my point there. Production for the first quarter tells the story. Almost 207,000 barrels of oil equivalent per day for the first quarter and current production is approximately 215,000 Boe per day, reflecting the momentum from 2014 activity such as first production from the 10-well Poteet density pilot and SCOOP that came on in March. Bottom line, Continental hit the brakes hard on capital spending and we were successful to the extent that we emerged from the first quarter $57 million below planned internal budget. In addition, both LOE per BOE and G&A per BOE of production for the quarter were better than annual guidance. That's excellent. So we adapted quickly and decisively to the new price environment. Throughout this downturn, we are conserving the strength of our balance sheet and targeting cash flow neutrality by midyear in preparation for the coming rebound in oil demand and pricing. Continental's teams are performing at a championship level. And obviously, we work closely with our drilling and service contractors as well as vendors throughout our supply chain to drive costs down quickly while maintaining valued relationships with them, our core service providers, while gaining efficiencies at the same time. Jack will expand on this, but we've already seen a 15% reduction in well cost in the Bakken and the SCOOP Woodford, and we expect additional gains by midyear. In addition to reducing operating costs, we are also creating shareholder value through operational efficiencies. A good example is in the Bakken, where we continue to optimize our drilling operation. As noted in our press release, the Bakken team recently set a new company record drilling a 2-mile lateral in 3 days, nearly 4 days faster than our average time to drill a lateral portion of the well in the basin. This same well is drilled from spud-to-TD in 13 days, nearly 5 days faster than our average spud-to-TD time. So far this year, the Bakken drilling team has TD-ed 8 wells in less than 14 days, and we continue to improve our operational efficiencies. World oil markets are recalibrating, and in the midst of this movement there are outstanding opportunities for independents. On a more global perspective, Continental has been working hard with other industry leaders to lift the U.S. ban on crude oil exports. The current environment of world energy markets perfectly illustrates why this should happen, and I'm highly optimistic we'll get this done this year. Senators and congressmen are becoming knowledgeable around this issue, and the fact that the ban is a 1970s era relic of the mix and price control administration that directly contradicts our commitment to free trade, it is becoming widely recognized that sufficient refinery capacity does not exist in America today to process American light sweet crude oil from shale plays such as the Bakken. And we, the producers, are subject to a steeply discounted value as a result. Success in getting the ban lifted will benefit the United States immensely in terms of energy development and security, job growth, trade balance and consumer stability of gasoline prices in the future. The time has come for this change. And that is summary of just one more reason why it's a great time to be in the U.S. oil business, and in particular a great time to be at Continental. America will again be an energy superpower in the world. I'm proud of the role we here at Continental play. Thanks for your support and now I'd like to turn the call over to Jack Stark.

[Jack H. Stark:]

Thank you, Harold, and good morning, everyone. We appreciate you joining us on the call today. As Harold mentioned, our teams have done a remarkable job taking care of business, given all the challenges they faced over the last 6 months. Thanks to their efforts, our first quarter results were on target or better than target on all metrics, which is a testament of the teams' understanding of our operations, our financials, our assets and our ability to adapt quickly to change. CapEx for the quarter came in $57 million under budget, driven primarily by lower service costs. Our service costs are currently down 15% on average, and we expect to see a 20% total reduction in costs by midyear. Production, on the other hand, was slightly ahead of budget for the quarter at 206,829 barrels of oil equivalent per day, up 7% from the fourth quarter of 2014 and up 36% from the first quarter of 2014. Given the drilling and completion activity budgeted for the remainder of 2015, we expect to see production growth to level off around midyear and project an exit rate for 2015 of approximately 5% above our 2014 exit rate of 200,000 barrels of oil equivalent per day. We anticipate having approximately 105 total gross wells waiting on first production at year-end 2015 as compared to 159 gross wells at year-end 2014. In the Bakken, our drilling program is proceeding right as planned. We have adjusted our level of activity, and we currently plan to keep 10 drilling rigs and 3 completion crews running through year-end. These rigs will be focused on developing our core acreage in Williams, McKenzie, Dunn and Mountrail counties as we move into the first stages of full-field development. Approximately 60% of our 2015 Bakken wells will be drilled on 660, 880 inter-well spacing in both the Middle Bakken and Three Forks reservoirs. We're planning to complete all of these wells with our 30-stage enhanced slickwater or hybrid technologies, targeting an average EUR of 800,000 barrels of oil equivalent per day. We continue to be very pleased with these results from our enhanced completions and have observed increasing initial 90-day rates and EURs per well as our data set builds. Our slickwater and hybrid completions are now showing an average initial 90-day production uplift of 50% to 40% respectively over nearby legacy completions in Williams and McKenzie counties. We are also seeing a corresponding uplift of 25% to 45% in EUR per well based on early time data, although we're seeing a significant improvement in the Bakken rates of return at the well level as costs are aligning with commodity price. A completed Bakken well currently costs around $8.2 million based on our 2-mile enhanced completion design, which is about 15% below our costs at year-end 2014. At a cost of $8.2 million per well and $60 oil, the rate of return on a typical 200,000 barrels of oil equivalent Bakken well is approximately 30%. We believe well costs will continue to decline as we realize operational efficiencies and service costs continue to align with oil price. We're targeting a completed well cost of $7.7 million per well in the second half of 2015. Now moving on south into Oklahoma. Our SCOOP step-out drilling program continues to deliver impressive results from both Woodford and Springer reservoirs. Our pilot density projects are also proceeding nicely and will accelerate our understanding of the optimal well spacing needed to maximize recoveries and returns from our exceptional SCOOP assets. In the Woodford, we completed 25 net, 59 gross operated and nonoperated wells during the quarter. The average maximum test rate for these wells was 1,430 barrels of oil equivalent per day, of which approximately 35% was crude oil, 65% was liquids-rich gas. Of significance, we began producing our 10-well Poteet density pilot test in late March. The maximum combined peak production rate for these 10 wells was an impressive 147 million cubic feet of gas and 3,240 barrels of oil per day. Of equal significance, Continental owns an average working interest of 94% in these 10 wells. Poteet is our first density test in the condensate window and was also our first dual level density test involving 5 wells each in the upper and lower Woodford. On average, these wells had a lateral length of 7,500 feet. This design was used to maximize the recovery from the Woodford reservoir that is approximately 385 feet thick at this location in Stephens County. We have more than 50,000 net acres with Woodford reservoir that is greater than 300 feet thick where this density drilling may be applied. Needless to say, we're very pleased with the early results of the Poteet density test and the implications it has for the resource potential of our SCOOP Woodford assets. We'll continue to monitor these results closely. During the quarter, we also completed several other notable Woodford wells that include the Thurston 135H in Grady County, which tested 5.7 million cubic feet of gas equivalent per day, which included 348 barrels of oil per day from a 4,569-foot lateral. Also we had the Singer well, the Singer 2-18-7XH in Grady Country, which tested 8.6 million cubic feet of gas equivalent per day, with 40 -- 423 barrels of oil per day as part of that production. And this was a 6,672-foot lateral. These were high working interest wells also, with Continental having a 93% working interest in Thurston and a 78% working interest in the Singer. In the SCOOP Springer, we completed 11 net, 15 gross operated and nonoperated wells during the first quarter of 2015. The average test rate for these wells is 1,081 barrels of oil equivalent per day. Of note, the Ramsey Trust 1-16-9XH was our first cross unit Springer test and it had a maximum 24-hour test rate of 2,235 barrels of oil equivalent per day from a 6,615-foot lateral. Other completions of note include the Omer 1-17H and the Jerry 1-15H, which had maximum test rates of 1,354 barrels of oil equivalent per day and 1,052 barrels of oil equivalent per day, respectively, from laterals averaging 4,600 feet in length. 81% to 85% of this production was crude oil. Continental had a 73% working interest in the Ramsey Trust, 75% working interest in the Omer and a 50% working interest in the Jerry. We also completed our second density pilot in the Springer during the quarter. The 4 wells in the Jeanna density pilot floated a combined peak production rate of 3,852 barrels of oil per day, of which 81% was crude oil. This is our second Springer density pilot located approximately 28 miles southeast of our 4-well Hartley density test. The Jeanna wells were drilled on 1,320-foot inter-well spacing with average lateral lengths of 4,400 -- excuse me, 4,644 feet. We have a 87% interest in the Jeanna unit. As in the Bakken, we are seeing well cost reductions of approximately 15% in SCOOP, and we expect to see additional reductions in costs through operational efficiencies as we gain more experience drilling and completing wells in this play. In addition to our Bakken and SCOOP programs, we continue to add value and evaluate new opportunities in both our Northwest STACK -- or excuse me, Northwest Cana and STACK plays located in Kingfisher, Blaine and Dewey counties, Oklahoma. In 2015, we began drilling our -- on our 31,000 net acres in the Northwest Cana project under the joint development agreement we have with SK E&S. Continental is operator and SK E&S is funding 50% of Continental's capital requirements until a $270 million carry is exhausted. We plan to have an average 4 rigs drilling in Northwest Cana throughout the year targeting the Woodford reservoir. In late April, we completed our first well, the Schantz 1-5-8XH, which is located in Blaine County. The well is flowing approximately 14 million cubic feet of gas per day at 3,900 pounds flowing casing pressure from the Woodford, and the rate continues to incline. In emerging STACK play, we have been monitoring activity for several months. Recent results from the wells completed by others in the Meramec reservoir have sufficiently encouraged us and suggest that the STACK play could become another significant platform of growth for the company. So we've got approximately 1,300 -- excuse me, 134,000 net acres in what consider the potential STACK fairway and have began drilling our first Meramec test to begin our assessment of the play. So with that, I'll turn it over to John.

[John D. Hart:]

Thank you, Jack. Good morning to everyone. Continental is well positioned to prosper today and as oil markets recover. Our focus is on maintaining financial strength and operational flexibility. We remain committed to these key objectives and expect to see continuing improving results as we move forward. EBITDAX for the first quarter was $439 million, resulting in a net loss of $132 million or $0.36 per diluted share. On an adjusted basis, excluding impairments and noncash gains on derivatives, we had a net loss of $34 million or $0.09 per diluted share. Our operating costs for the quarter were excellent, with performance better than annual guidance. Lease operating expense was $5.05 per Boe, while DD&A was $21 per Boe and cash G&A was $1.85 per Boe. Total cash cost including interest was lower at $13.61 per Boe in the first quarter, improving by 23% as compared to the full year 2014. Our improved cash costs are a reflection of our teams' commitment to lowering operating costs and improving efficiencies. Property impairments for the first quarter totaled approximately $148 million, inclusive of producing and non-producing assets. Proved property impairments were $70 million, reflecting the impact of lower commodity prices in certain noncore areas, and the remaining charges of $77 million reflect recurring amortization of undeveloped leasehold. There were no impairments of Bakken- or SCOOP-producing assets. First quarter oil and gas differentials were consistent with our guidance at $10.01 for oil and $0.28 for natural gas. We anticipate the softened price for NGLs will improve in the near term as crude supply rebalances and as it correlates to the price of oil. North Dakota recently modified its tax structure to reduce the all-in combined production tax rate to 10%, while eliminating existing rate triggers in 2016. The WTI average is above $90 for 3 consecutive months. The rate will rise to 11%. This new structure will be effective beginning January 1, 2016. As Harold and Jack noted, we are under budget for CapEx year-to-date, providing strong momentum towards cash flow neutrality by midyear 2015. We plan to spend approximately 2/3 of the capital budget in the first half of the year and the remaining 1/3 in the second half. Therefore, our run rate of CapEx spend in the first quarter is not indicative of the remainder of the year, as we expect the rate to decline significantly from quarter to quarter. At a $60 benchmark WTI, we would be cash flow-neutral by midyear. Strip prices have risen significantly recently, while costs are continuing to decrease and our level of spending is coming down. So we are closely approximating neutrality now and expect to achieve it shortly. In relation to our annual guidance. Obviously, we are performing extremely well on a number of measures. As we have indicated previously, we want to see strength and stability in oil prices before adjusting our guidance. We have an adaptable program where we can scale production up or down to reflect market conditions. Although we could likely be comfortable in adjusting certain elements of our guidance today, we are electing to monitor oil prices for another quarter. As for now, production is trending towards the upper half of our guidance, while LOE and G&A are trending towards the low end or better of our guidance. This reflects how well our teams and assets are performing. On the finance front, we continue to have ample liquidity and no near-term debt maturities, allowing us to control how we deploy capital in 2015 with no near-term needs to tap the capital markets. At the end of 1Q, we had $48 million of cash on hand and we currently have availability of $1.3 billion under our credit facility. On March 12, Moody's issued a credit opinion reaffirming our investment-grade rating and stable outlook. In 2015, both Moody's and Standard & Poor's have reaffirmed their ratings, an indicator of the quality of our assets, our approach to managing through the current cycle and our financial strength. We remain committed to maintaining our investment-grade rating, and we will continue to operate prudently during this downturn. Again, let us thank you for joining us on the call today. Now we will be glad to take any questions that you may have. Operator, would you please provide instructions for asking questions. Thank you.

[Operator:]

[Operator Instructions] From Morgan Stanley, we have Drew Venker on the line.

[Andrew Venker:]

It's very nice results out of Northwest Cana, and sounds like you guys are definitely getting excited about the Meramec as well. Can you talk about your goals for the program this year, I guess, both in Northwest Cana and within STACK?

[Jack H. Stark:]

Sure, Drew, this is Jack. Northwest Cana, we've just got plans to keep 4 rigs in there throughout the year. And in STACK, we have 1 rig, that we have drilling right now. We're probably going to keep that rig in there clearly for another well or 2. We may actually keep it in there for the remainder of the year. Just depends on what we see in the results from some of these initial tests.

[Andrew Venker:]

And Jack, among that STACK program, did you plan to drill any Osage wells this year? You guys highlighted that as a potential target.

[Jack H. Stark:]

It's another of the reservoirs that has potential out there. But at this point, we're targeting Meramec, which is what we've seen others target out there and have good success.

[Andrew Venker:]

And I guess lastly on STACK, if you continue to be encouraged by the results, are you going to focus drilling in one area? Or are you planning to delineate the entire position?

[Jack H. Stark:]

Well, one of the advantages we have in this area is there's penetrations in the area that give us at least some framework of control here. But it is -- it will require some delineation. So I see us starting out probably playing a little bit close to the vest to where there is some known good results, and just walk our way out. About 65% of our acreage, I believe, that's right, Steve, is HBP-ed in this area, because there's a lot of legacy acreage in here as well, and -- is that right, Steve?

[Steven K. Owen:]

It's about 51%.

[Jack H. Stark:]

About 50%, okay, of our acreage is HBP-ed. And so we really, I guess I'd say I'm not under the gun to really get aggressive here. I think we'll just -- we're going to step into this prudently.

[Andrew Venker:]

And then on the costs side, obviously, service costs have fallen quite a bit. Do you have any efforts underway to reduce costs by just changing well design, in addition to service costs concessions?

[Gary E. Gould:]

You bet. This is Gary Gould. We continuously look at operational efficiencies. And so we are analyzing every piece of our drilling design, whether it be the vertical or the curve or the lateral. And you'd see some of our improvements that were described by Harold in our -- the speed in which we're drilling our lateral in the Bakken. We're doing the same type of analysis in the south. We also have -- besides just talking with our vendors day-to-day about operating costs, we also talk to them day-to-day about our operations. We also have quarterly meetings with them, where we discuss safety as well as performance as well as costs. We're also looking at short-setting some of the casing, which could provide as much cost savings as $500,000 per well.

[Operator:]

From Bank of America, we have Doug Leggate on line.

[Douglas George Blyth Leggate:]

Jack, I wonder if I could ask you an operational question about the Poteet test. Maybe my math's wrong. But if this has been on since the beginning of March, assuming it's the 1st of March, and looking at the cumulative production you've had out of that, it looks like the rates are well above the 30-day kind of type curve that you gave us back at last year's Analyst Day. I'm just curious, with the pressure you're showing on the well, I'm just curious if there is anything unusual about how you're operating that test? Or is this indicative that things actually are putting out a little better than you'd guided to? And I've got a follow-up please.

[Jack H. Stark:]

Well, these Poteet tests here, I mean, they are really performing right in line with what other wells in that area had done. In fact, I'm impressed with how they're performing here early time. Remember, we had our Claudine and Chalfont wells that were some of our highest IP wells in this same area, and those are excellent wells. And so the performance variance that you're seeing there, that you're working on, is probably just reflective of some operational variations that happen out there because what we're looking at is just a cumulative production for that period of time. But Gary, do you have anything you want to add to that?

[Gary E. Gould:]

I'd just add that the completion design that we put on these wells was hybrid design. It's very similar to some of the other hybrid designs that we do in the area. And so this is an area with the thickness of 380 feet or so, so it's a very good area for us. But you also heard that we have 50,000 net acres of more than 300 feet of Woodford, where this type of density could be applied. So we've got a large acreage position in which we feel like we can develop this way.

[Douglas George Blyth Leggate:]

So just to be clear though, the lower type curve you gave is an average across all the acreage, looks like it's the sweet spot. Is that fair?

[Jack H. Stark:]

Well, this is a very good area here, but these wells are performing really in line or even above the offsets around here. There's no doubt about that and we're very pleased with the way they're performing. So -- But as Gary said, the completions, there's nothing really unique about the completions. We -- the fact that we've actually looked at harvesting this, with the upper and lower half being penetrated here, may actually be part of how these wells are performing quite well. So this is part of why we're doing these density tests and doing the upper and lower half tests is we're trying to find out what is the optimum pattern for development when we're this thick. What excites me about this test here is that we've got over 50,000 net acres that have 300 feet of thickness of Woodford or greater. And when you consider developing that -- those net acres, say, with 7,500-foot laterals on this density, you end up with over 500 wells, net wells that could be drilled in those areas. And in some of these areas, it gets upwards to 900-foot thick. So when you start putting the reserve model to those number of net wells, you're looking at something that's -- just use 1.5 million barrels equivalent per well, 750 million net barrels to the company. So it validates what we've said back in September at our Analyst Day that the potential of the SCOOP area is -- basically, competes head to head with the Bakken.

[Douglas George Blyth Leggate:]

Jack, I don't want to belabor the point. Just want a yes or no answer on this one hopefully. Will these facilities constrained or choked back in any way?

[Gary E. Gould:]

On the Poteets, we're flowing at pressures of between 1,500 psi and 2,500 psi, casing pressure, so no facility restraints though.

[Douglas George Blyth Leggate:]

Okay. My follow-up, and I'll be quick, is just on the 1,000 barrel type curve on the Bakken, Jack, is does that assume the uplift that you provided on the hybrids and slickwater fracs? And if so, what proportion of the wells are assumed? And then if you're going fully to that kind of design, is the 800,000 number still good? And I'll leave it there.

[Jack H. Stark:]

Yes, the 800,000 barrel equivalent number is the same number we've used previously, and we didn't adjust it for the increase, the uplift that we're seeing from these enhanced completions. You did see a net gain of, what, 5% to 10% in initial rate, maybe 10% in EUR, from what we've reported here. And so we are seeing actually better results from this, but we did not change the 800 MBoe equivalent. That's the same number we've been using. And -- but that was uplifted based on our prior -- it does have, I think, a 25% uplift from -- based on an earlier enhance completion results. Is that clear? I think I might have confused that. Bottom line, yes, it does have an uplift in it of about 25% to 30% from what I'd call our earlier enhanced completion results. It does not include the increased results that we're seeing right now.

[Operator:]

From Guggenheim, we have Subash Chandra on line.

[Subash Chandra:]

A question on the enhanced completions. Do you think that it steepens the treadmill, keeps it constant or reduces it as you look into '16?

[Gary E. Gould:]

When you say steepen treadmill, what do mean by that?

[Subash Chandra:]

So the decline rate of these wells, how does that change the shape of it versus the prior completions? So is it a higher IP, steeper decline? Or does the decline kick in later in the life of the well at a steeper rate?

[Gary E. Gould:]

I get what you're saying. The way -- we're still early in the response for that. But the way that we're modeling it right now and based on the production results we've seen so far on a 90-day average, we believe that the IP increases by about 25%, but the decline characteristics are the same. And that's what that 800,000 Boe model is based on. And as you can see, we continue to see improvement from one quarter to the next. You can see how our rates have improved and our EUR estimates have improved from this quarter compared to last quarter as we get more well results coming in. So we continue to be encouraged there.

[Subash Chandra:]

Okay. The second question is do you have a view, a revised view of potential growth rate in 2016 spending within cash flow, sort of assuming Harold's price environment that he thinks is sustainable?

[John D. Hart:]

Yes, if you look at -- I think you're asking in terms of the constant price environment. Our maintenance cap, going into 2016, is somewhere in the range of $2 billion to $2.2 billion. We're continuing to see cost improvement during the balance of this year, and I expect we'll see a little bit more next year. So to maintain a flat level of production in '16 off of '15 would be $2 billion to $2.2 billion.

[Subash Chandra:]

Got it. Okay. And the final one for me...

[John D. Hart:]

Anything above that, we would be growing.

[Subash Chandra:]

Yes -- I'm sorry, I cut you off. I'm sorry.

[John D. Hart:]

Anything above those levels, we would be growing production.

[Subash Chandra:]

Right, okay. And a final question from me. You talked, I think, about the Bakken well drilling the lateral out in a couple of days. When you look at the Cana relatively, is it more sensitive to staying in zone? Is it tougher to stay in zone, et cetera? Trying to get a picture of what you think the optimal -- what you can get to in the Cana relative to the Bakken.

[Jack H. Stark:]

As far as the drilling target is concerned, no. Actually in Cana, we got a thicker section to target there, and so it's actually easier to drill.

[Harold G. Hamm:]

Yes, that -- basically, we're dealing with 2 sets of rocks here, and Woodford just drill slower and depending upon the section that we're in. So we just don't have the as speedy drilling as we do up in the Bakken.

[Operator:]

From RBC Capital Markets, we have Leo Mariani.

[Leo P. Mariani:]

You kind of indicated that you will review the budget at midyear here. Also you folks indicated that you thought there was upside in crude prices later this year. Just trying to get a sense of what type of crude pricing environment you'd like to see before you decided that it was time to bring some rigs back to work here?

[Harold G. Hamm:]

We're going to be looking at that closely. But as you know, $70 a barrel is a price that turns it on for us, I believe. And basically, we could see that happening in several instances.. So as we start looking at the short supply situation, obviously, that is apparent out there on the Horizon, with the amount of rigs that's shut down, that could happen fairly soon. Also if we are not having the discounted oil into the market, as we are right now, due to this refinery shortage situation for light tight oil, you could gain quite a bit as well. So that could be reached quickly.

[Leo P. Mariani:]

Okay, that's helpful. And I guess, just looking at the Springer here, it's kind of in earlier stage of development versus other parts of SCOOP there. Just trying to get a sense of how much of the acreage you think has been derisked that you've got there in the SCOOP for the Springer formation?

[Jack H. Stark:]

Leo, this is Jack. From a geologic perspective, the distribution of the Springer is really fairly well defined from all the Woodford penetrations that we've experienced or have been drilled out here. And so we really have been able to essentially surpassed, say, the initial delineation phase and go right into a development phase here, I'd call it, so we can start out from some of the core and thicker areas and work our way out. So from a geologic distribution standpoint, we have a pretty good handle on it, now is just assessing the economic derisked areas throughout it. And so right now, we've got 46,000 net acres that we call derisked, as we've said previously, out of the 200,000 net acres we have. And that's in the oil window. And we put about 127 million barrels net equivalent potential to the company, but we've got a lot more running room here to go. And as we continue to drill, we'll be able to add more and more of that to our derisked economic footprint for the play.

[Leo P. Mariani:]

Okay. I guess just going over to the SCOOP play. Just in general, obviously, it's a newer play than the Bakken. You've clearly seen some dramatic cost improvements over many years in the Bakken just from efficiencies. Just trying to get a sense of kind of roughly what inning you guys think you're in terms of efficiency improvements in SCOOP? If you think there's a lot more to go there over the next few years kind of like you did at the Bakken?

[Jack H. Stark:]

You bet. We've been at the Bakken for over 10 years, and you can see the efficiencies we've gained, whether it be on the drilling and completion side. And we'll apply those learnings that we have from up there. But it is different rock, as Harold talked about, and so really, we're just in the second inning or so of a 9-inning game here as we continue to work on efficiencies. And we usually see higher efficiency percentage increases in those first few innings. So we're very optimistic about seeing additional operational efficiencies on top of our cost reductions that we've seen.

[Operator:]

From Goldman Sachs, we have Brian Singer on line.

[Brian Singer:]

You talked to being very close to cash flow neutrality now here at today's oil prices and costs. Historically, Continental has spent -- has outspent its cash flow. And I wondered if you could just take us through how you're thinking about that on a going-forward basis? Obviously, in a downward oil trajectory, reining in the CapEx makes sense, but I wondered if you feel like this is a more secular shift towards staying within cash flow. And if not, what the limitations do you see are in terms of how you think about outspending down the road?

[John D. Hart:]

We've always -- we focused on being a balanced company. Cash flow spend is one element of that. But what we really focus on is the underlying debt metrics, due to the quality of our assets with the high rates of return we've historically generated in the Bakken and SCOOP. We've had a very advanced recycling of cash, even though we've outspent, we get it back very quickly, and our debt metrics have actually improved over that previous period. At our core and with the depth of inventory we got, that we have, we are -- we're an absolutely a growth company, and we look to that in the future. But we also look to maintaining balance -- getting the investment grade was very important to us. It's important to us to continue to preserve that and grow that. So there's not an absolute answer in terms of the level of spend, but the absolute answer is in level -- in regards to maintaining this financial strength of the company and its various metrics. And I think we've done a pretty good job of balancing those, and we'll look to do that in the future while continuing to derive shareholder value by growing the company and realizing the value of the assets that we have.

[Brian Singer:]

Great. And my follow-up is just with regards to the cost coming down and the cost deflation you've highlighted in areas like the Bakken. Can you talk to what -- if you were to spread it up between -- or split it up between what you think is more secular, i.e. your own efficiency gains and improvements versus what is more service costs-related and more susceptible or maybe you don't think more susceptible to, going back up, if oil prices rise or even stay where they are right now?

[Jack H. Stark:]

Well, first, I would say I think most of the cost reductions that we've seen on the service side, in regards to just the vendor cost, are structural. I mean, we're in a situation where the price is much lower and activity is much lower than it has been in the past. And so I think these are structural changes based on supply and demand and activity of drilling rigs and stem crews. As far as the percentages, the 15% that we've seen so far is mostly driven by vendor cost. And so additional operational efficiencies are upside to that. We expect to see an average of at least 20% in terms of vendor cost for the second half of the year. And so in addition to that, we expect to see more operational efficiencies as we continue to learn how to drill and complete wells better, yes, and I would expect that more of those would be in our Oklahoma play than up in the Bakken. And so we might see 5% to 10% at least in the south as it's a new play. And we'll continue to work toward 5% improvement after over a decade of drilling wells in the Bakken.

[Operator:]

From Howard Weil, we have Brian Corales on line.

[Brian M. Corales:]

Just kind of follow-up on Leo's question. How far away -- I mean, how close to HBP-ing the SCOOP are you? I mean is that 2 years out, 3 years out? I guess what I'm getting at is when is the majority of the rigs is going to be kind of at full-field development like that Poteet pad was?

[Steven K. Owen:]

Well, this is Steve Owen. From a land standpoint, we are 44% HBP-ed in the core currently. And by year-end, we'll be over 50%. We continue to utilize our drilling programs as part of our HBP program in addition to our renewals and extensions.

[Brian M. Corales:]

I guess you mentioned on the Poteet wells that frac-ing I guess the upper and lower, I mean, could you see a benefit by frac-ing those together? Is that kind of one of the thoughts you have?

[Jack H. Stark:]

Well, as far as frac-ing them together, we did frac them at the same period of time. So we went and drilled all these 10 wells, frac-ed them all at the same time. And their well spacing is approximately, is a little over 1,000 feet at the same level. And even if we're talking upper or lower, over 500 feet apart. And so we see that as very effective overall pattern for stimulating these together.

[Brian M. Corales:]

Okay. So are those getting -- because they're being frac-ed together, getting better results than say a one-off well?

[Jack H. Stark:]

No, there's no reason, by doing that, necessarily gets that much better than single wells that are HBP-ing acreage in other parts of our play.

[Brian M. Corales:]

All right. And just one final question. You had the slide with the enhanced completion showing the step up with the slickwater. What is the EUR shown for the average standard completion. Is that 800,000 barrels? Or is that 600,000?

[Jack H. Stark:]

No, it'd be 800,000 divided by 1.25, so a little bit over 600,000. And just for clarity, that's for the standard old design that we are no longer implementing this year.

[Operator:]

From Simmons & Company, we have Pearce Hammond on line.

[Pearce Wheless Hammond:]

In the last quarter, when you had talked about the possibilities of 2016, you'd mentioned that you could hold CapEx, I think, roughly flat and grow production in sort of the single digits. And so one quarter on and you've seen where the cost savings have trended, where well productivity has moved to, do you think that actually you could see either a lesser rate of spend for the same amount of growth or commensurately, the same amount of spend but more growth?

[John D. Hart:]

We -- a flat level of spend, that's the 2.7. And at that, we would grow in those ranges. So that is factoring in probably a little higher activity level because of cost savings. In the current price environment, we certainly would see a continued improvement in costs, not only in terms of rates and prices in that regard, but obviously, in terms of efficiency, as Gary is giving some examples of. Today, we gave a little more color. I think I gave it last time also that at flat level of production, our maintenance capital is going to be closer to $2 billion to $2.2 billion. That factors in cost savings and efficiencies as well that we would expect to garner.

[Pearce Wheless Hammond:]

And then given that oil prices have moved up a little higher here recently, if you were to increase activity, would it be, first, from a staging standpoint, would it be first adding completion crews and then working down the well inventory, and then there's some time lag before you would add rigs after that? Or would it be somewhat simultaneous? And if you did add rigs, would it be in the Bakken or in the SCOOP?

[Jack H. Stark:]

We would first be working down our inventory with more completion rigs.

[Harold G. Hamm:]

And the second part of that question, looking at the lease requirements will depend on where they go, into SCOOP or Bakken. So we're in awfully good shape on lease requirements in the Bakken, so might very well be in the SCOOP.

[Operator:]

From Heikkinen Energy, we have Marshall Carver on line.

[Marshall H. Carver:]

You completed more wells than I was expecting in the SCOOP and Williston in 1Q. How will the remainder of your 2015 completions be spread between 2Q, 3Q, 4Q?

[Jack H. Stark:]

They'll be relatively even. Right now, we're looking at 3 stem crews in the Bakken from here on out, and then also we're planning to manage 3 or 4 in Oklahoma from here on out. It's possible that as we look at our inventory, that we may pick up another crew at some point in the Bakken. It will just -- we have the flexibility to manage our production in CapEx. But right now, we're looking at a flat number there.

[Marshall H. Carver:]

Okay. And one question on Slide 12. You showed the 2 dashed black lines for the 7,500-foot next type curve. Why are you showing 2 lines instead of 1? Is that 1 line for -- is that a high and a low based on historical wells? Or is one of those lines for the upper Woodford and one for the lower Woodford? What are those 2 dashed black lines represent?

[Gary E. Gould:]

Unfortunately, Marshall, it sounds like your printer is printing out 2 lines. We have a printer, or a couple of printers around here that do the exact same thing. And we didn't know that, that was still an element of that slide. But -- so you're seeing 2 lines, but there shouldn't be 2 lines there. I apologize for that. But the line that you want to track is the one, I believe, will be the top line, top of the 2, all right? Ignore the other one. Somehow we couldn't get rid of that evidently.

[Operator:]

From IHS, we have Sven Del Pozzo on line.

[Sven Del Pozzo:]

I was hoping if you can give me a little spatial orientation as to where you're doing the hybrid -- in the Bakken, hybrid versus slickwater fracs?

[Jack H. Stark:]

Yes, we're actually continuing to test both throughout the area. And so the hybrid may not give us as much initial rate but it doesn't cost us as much, and so we continue to do tests throughout our area on both of them.

[Sven Del Pozzo:]

So in the vicinity of each other as well?

[Jack H. Stark:]

That's correct.

[Sven Del Pozzo:]

Okay. And the decline in SCOOP rigs versus the decline in the Bakken rigs, I was just wondering whether -- at least in the Woodford part of the SCOOP play, where the economics probably are affected more than the Bakken by a decline in NGL and gas prices, I was wondering, kind of similar to the gentleman's question earlier, where you'd be most inclined to reduce rigs or add them? So say the commodity price environment is similar to today's between gas, NGL and oil, would you rather add a Bakken rig or add a SCOOP rig?

[Gary E. Gould:]

We really are seeing -- it depends on the area. So if you look at it, we could go into portions of SCOOP and get exceptional economics, and it's just that all areas are not equal. So yes, we could move in and we could target our highest rate of return areas either in the Bakken or SCOOP with a rig and they compete pretty much head-to-head. So it really comes down to what we perceive the commodity environment to be at that time, the availability of rigs and what makes sense logistically. So fortunate thing is that we can put them in either one and make great economics.

[Sven Del Pozzo:]

Okay. And last thing, has the definition of an enhanced completion changed since your analyst meeting last September? I think at the time, that was something like 4 million, 4.5 million pounds of proppant per well. What would you classify as an enhanced completion today in the Bakken?

[Jack H. Stark:]

In the Bakken, the way we classify them is hybrids and slickwaters. So it could have been back at our Investor Day in September that we were also talking about shale fracs with more sand at that time. We've been able to eliminate that as one of our enhanced stimulation. So now we're focusing just on hybrid and slickwater, and we continue to test as far as how much sand is optimum.

[Sven Del Pozzo:]

Okay. And what about testing of types of sand or is that standard across the Bakken?

[Jack H. Stark:]

Yes, we continue to test those as well. We've seen such a great step change increase with the slickwaters and hybrids. And now we continue to analyze other things such as stage lengths or types of sand and amounts of sand.

[Operator:]

And our last question, from Morningstar, we have David Meats on line.

[David Meats:]

I just wanted to follow up a little bit on the current budget. Are you guys still on track for the $2.7 billion still? Because I know you spent quite a bit in the recent quarter.

[John D. Hart:]

Yes, the first quarter, you can't take it and annualize. It's -- coming into the year, we came in with about 50 rigs. We're down to about 30 now, and so you see that step-change. We expect to see about 2/3 of our CapEx in the front half of the year and about 1/3 in the back half of the year. In regards to the $2.7 billion, in the first quarter, we were $57 million under what our internal budget was for the quarter. And for the full year, right now, we're projecting, we're on a trend today that would be less than our $2.7 billion by about $150 million to $200 million. So we're operating inside of that budget currently, and that gives us a lot of flexibility as we go throughout the balance of the year.

[David Meats:]

Okay, perfect. One quick follow-up. We've seen a decent level run-up in oil prices in the last month or 2. I was just wondering at what point is it time to start consider adding downside protection?

[John D. Hart:]

Sorry, at what point would we consider downside?

[David Meats:]

Downside protection, adding hedges?

[Jack H. Stark:]

Oh, okay.

[John D. Hart:]

Hedges. Yes. Not -- certainly not at the current prices, I think, we would need. Hedging is something where we're looking not only to price but rebalancing. We're not anywhere near a point where we would enter into hedges, particularly as we're getting to cash flow neutrality very quickly.

[Operator:]

And we'll take one more question from Ladenburg Thalmann, we have Noel Parks on line.

[Noel A. Parks:]

Just a question. I remember back at the time of the Analyst Day, you were talking about maybe some experimentation with completion order of the wells within a pad in the Bakken. I think there's a mention of having seen some preferential drainage into, I believe, was sort of original wells and looking at trying to sort of engineer a different stress regime. Did that pan out? Is that something you're pursuing? Or is that just secondary to what we've seen with service cost as far as adding value?

[Jack H. Stark:]

I recall some discussion on that at Investor Day. I believe it was around the Hawkinson microseismic work that we showed. I would say the main thing we're doing now is we're moving into the Bakken based on our density test as well as results of our enhanced completions, and we're moving into the first step of full development. And so what you see is approximately 60% of the wells that we're drilling this year in the Bakken are moving into full development where we're targeting that optimum spacing that we've determined.

[Noel A. Parks:]

Great. And I'm sorry if this was mentioned before, but do you have sort of an updated estimate of the Springer inventory you have at this point?

[Gary E. Gould:]

No, we have not updated that since prior calls. We're just very slowly stepping this out. As I've said before, we don't really have to do much delineation drilling here to understand where the Springer reservoir exists. We've been -- had the benefit of all the Woodford wells and penetrations that we've had out in that area, it helps us to basically know where the reservoir exists. And so what we're doing is just slowly stepping out and derisking the acreage economically from what we consider to be, say, the core areas. And so we still haven't reached the limits of those areas that we've stepped out. We haven't done really any significant step outs at this point because we didn't need to. And so that's -- so it will grow though, that inventory will grow.

[Operator:]

And this concludes our question-and-answer session. We will now turn it back to Warren Henry for closing remarks.

[J. Warren Henry:]

Again, thank you for joining us on our call this morning. Thank you for your questions and have a great day.

[Operator:]

And ladies and gentlemen, this concludes our conference. Thank you for joining. You may now disconnect.