Continental Resources, Inc.
Q4 2015 Earnings Call Transcript

Published: 25 Feb 2016

[Operator:]

Good day, ladies and gentlemen, and welcome to the Continental Resources Inc. Fourth Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. As a reminder, today's program is being recorded. I would now like to introduce your host for today's program, Mr. Warren Henry, Vice President of Investor Relations and Research. Please go ahead.

[J. Warren Henry:]

Thank you, Jonathan. I'd like to welcome everyone to today's call. Joining us 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 on the call this morning and available for Q&A will be Jeff Hume, Vice Chairman of Strategic Initiatives; Glen Brown, Senior Vice President, Exploration; Gary Gould, Senior Vice President, Production and Resource Development; Pat Bent, Senior Vice President, Drilling; and Steve Owen, Senior Vice President of Land. Our call today will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially 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 risks. In addition, Continental does not undertake any obligation in the future to update our forward-looking statements made on this call. Also on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of non-GAAP measures to generally accepted accounting principles, please refer to the updated investor presentation that has been posted on our website at www.clr.com. To begin this morning, I'll turn the call over to Mr. Hamm for his comments.

[Harold G. Hamm:]

Thank you, Warren, and good morning, everyone. We appreciate you joining our call today. Continental ended 2015 with a solid fourth quarter that was characterized by continued positive trends in key operating and financial metrics, strong production, low operating cost and effective discipline as we work to balance cash flow with capital expenditures. Production was 224,900 Boe per day, as we anticipated, just a small reduction in the third quarter 2015, as we scaled back well completion activities. We continued to reduce operating cost per Boe of production with a fourth quarter result of $3.86 per Boe in production expense, cash G&A expenses were also very favorable at $1.68 per Boe of production. These positive trends were delivered despite the third quarter to fourth quarter's declined production, which is yet another testament to our operating team's focus on efficiency and cost discipline. Finally, despite a significant decline in oil prices through the fourth quarter, we managed to end 2015 with fourth quarter capital expenditures, almost in balance with cash flow. For 2015 as a whole, we came in under our total CapEx budget by $200 million, in line with the outlook we shared on our third quarter earnings call in early November 2015. So, we ended 2015 with a solid, disciplined quarterly performance and we really look ahead. Now I want to focus on Continental's future and two recent accomplishments that should pay big dividends for all of us moving forward. First, we announced our continued success in delineating the over-pressured STACK play in Oklahoma. Second, we have significantly increased recovery per well in the SCOOP Woodford, with enhanced completions in the condensate window. Jack will provide greater detail on these achievements. The key point is, exploration success and technology improvement are ongoing and these plays just keep getting better. This is not simply Continental's view. Several analysts recently identified the core Bakken, SCOOP Woodford, SCOOP Springer and STACK as top quartile resource plays in the United States. Based on the analysts' expected rates of return in these plays, like Continental, they see these as the premier value plays for growth when commodity markets rebalance and prices do recover. They are the platforms in which Continent will build shareholder value and the recovery and beyond. We expect the process of rebalancing and recovery will start in the next six months to nine months. As the process gets underway, Continental will remain disciplined with their capital spending and cost control. We're preparing to grow prudently with discipline, a very measured approach to maximize price, once we confirm that the eventual price recovery is sustainable long-term and not just a spike like we had in mid-2015. The market will rebalance, and when it does, we'll be prepared to operate likewise in a changed market environment. With the U.S. crude oil export ban finally lifted, we have a historic opportunity to again reestablish the United States as the world energy leader as it was in 1950s and 1960s, based on truly free world energy markets. We must reestablish growth that reinforces U.S. energy security, benefits our country's economy and brings hundreds of thousands of jobs back to the oilfield and related industries. I believe and I've testified in Congress that free trade of crude oil will reduce overall price volatility, especially to the degree that we've seen in 2008, 2009 and the past 18 months. The industry will again attract the investment capital required for the next stage of the American Energy Renaissance and deliver to American consumers a stable, low cost supply of transportation, power generation, fuels that will support economic growth for everyone. In closing, let me say again how proud I am of the Continental team and how they performed this past quarter and in 2015 as a whole. We demonstrated the quality of our people, our established culture and our assets. I'm confident the benefits will accrue to our shareholders in the not-so-distant future. With that, I'll turn the call over to Jack Stark.

[Jack H. Stark:]

Thanks, Harold, and good morning, everyone. We appreciate you joining us on our call today. I want to echo Harold's comments regarding our employees and thank them for doing a tremendous job in 2015. The technical advancements and operational efficiencies they developed during 2015 and our ongoing efforts in 2016 will pay dividends for Continental and shareholders for years to come. Today, I'm going to focus on some important results from our drilling and completion activities in the over-pressured STACK and SCOOP Woodford plays. I will start with the over-pressured STACK where we couldn't be more pleased with the performance of the Meramec wells we have completed to date. Since our first recompletions reported last year, we've completed three additional Meramec wells, and I have to say, the results are quite impressive. Bottom line, these STACK wells are delivering some the best rates of return in the company and rank among the best performing wells I've ever been involved with in my 35-year career. The three new wells were strategically located to demonstrate repeatability and expand the known productive footprint of the Meramec underlying our 155,000 net acres in STACK. The largest of the three new producers is the Boden 1-15-10XH well, which flowed at an exceptional 24-hour rate of 1,000 barrels of oil in 15 million cubic feet of gas per day or 3,508 barrels of oil equivalent per day from a 9,800 foot Meramec horizontal. It's important to point out that the Boden well produced this rate at a flowing casing pressure of approximately 5,400 PSI, reflecting the strength of the well and the benefit of the over-pressured nature of the Meramec reservoir underlying our acreage. The Boden was a significant step out located 16 miles southwest of our Ludwig well and represents our deepest and most over-pressured test of the Meramec reservoir to date, at a vertical depth of 12,550 feet. The Boden has been producing for 82 days and most of that time, it's been produced on a restricted choke. During that time, it produced approximately 144,000 barrels of oil equivalent with 28% of the production being oil. The well continues to flow at a restricted rate of 410 barrels of oil and 6,300 Mcf per day at approximately 5,350 PSI flowing casing pressure. The other two new producers were the Compton 1-2-35XH and the Blurton 1-7-6XH, which are located five miles southwest and three miles northwest of our original Ludwig well, respectively. The Compton flowed at an initial 24-hour rate of 2,547 barrels of oil equivalent per day at a flowing casing pressure of 2,850 PSI and 71% of the production was oil. The Blurton flowed at a initial 24-hour rate of 2,328 barrels of oil equivalent per day at a flowing casing pressure of 2,775 PSI and 78% of the oil – production was oil. The Compton has produced approximately 80,000 barrels of oil equivalent in its first 41 days online and the Blurton has produced approximately 54,000 barrels of oil equivalent during its first 34 days online. Both wells continue to produce at restricted rates of 1,670 barrels of oil equivalent per day and 1,695 barrels of oil equivalent per day, respectively. The performance of these three wells continues to support our observation that wells completed in the over-pressured window of STACK produce at rates three times higher than was completed in normally pressured window of STACK during the first 90 days on a normalized 9,800-foot basis. This bodes well for Continental as approximately 95% of our 155,000 net acres of STACK are located in the over-pressured window. In addition to announcing three new producers yesterday, we also introduced our preliminary economic model for wells completed in the over-pressured oil window of STACK. We define the oil window as areas where oil – where the oil and gas ratio was less than or equal to 10,000 to 1. Based on the early time performance of 14 Meramec wells completed by Continental and others in the over-pressured oil window of STACK, our estimated ultimate recovery for a 9,800-foot lateral well currently stands at 1.7 million barrels of oil equivalent per well. This delivers a 55% rate of return at a completed well cost of $10 million, assuming $40 WTI and $2.25 per Mcf gas. The $10 million completed well cost reflects the cost of drilling in the deeper, over-pressured oil window of STACK where intermediate casing is required. We currently believe approximately 30% of our acreage lies within the oil – over-pressured oil window of STACK. By comparison, the economics of the over-pressured oil window of STACK rank among the best opportunities in the U.S. We will develop our economic model for the over-pressured condensate window as more data becomes available, but I'll have to say that with the Boden well as our first over-pressured condensate well, we expect the economics will also rank among the best in the U.S. Now, let's move on to the SCOOP Woodford where technical teams have raised the bar of performance once again. Over the past year, our teams have tested various enhanced completion techniques on 15 wells over a broad geographic area in the SCOOP condensate window. Proppant per foot was a key variable, ranging from 900 pounds up to 1,800 pounds per foot. All 15 of these wells are outperforming the legacy offset wells completed with our standard completion. Seven of the wells have 90 to 180 days of production history, and showed production lift of 30% to 35% compared to legacy offset wells. Based on the performance of these enhanced completed wells, we have updated our economic model for our 7,500-foot Woodford condensate well. In our new model, we have increased our expected UR 15%, from 1.7 million barrels of oil equivalent per well to 2 million barrels of oil equivalent per well. The incremental cost for an enhanced completion is approximately $400,000, which is more than justified based on the improved performance of the wells. This puts the current cost of an enhanced completion well at $9.9 million. We fully expect these costs will decline during 2016 through efficiencies and we are targeting a completed well cost of $9.6 million. At the targeted cost of $9.6 million, an enhanced completed well generates a 25% rate of return, assuming $40 WTI and $2.25 per Mcf gas. Going forward, all SCOOP wells will be completed using enhanced completions. Testing of these in higher proppant volumes will be conducted during the year as we continue to seek the optimal completion design. Recent tests using these higher proppant volumes are showing promising results. One other highlight from SCOOP Woodford I'd like to mention is the Vanarkel density pilot. The Vanarkel is our third density pilot to be completed in the condensate fairway. The other two included the 10-well Poteet and Honeycutt pilots. The Poteet has been producing for about 350 days, the Honeycutt approximately 250 days, and the Vanarkel almost 70 days. The key point I want to make is that all wells and the pilots continue to produce at rates above our type curve and to date have shown no signs of well interference. This is quite significant as it helps validate our vision for full field development. We currently have two additional density pilots underway including the eight-well Newy pilot that is completing right now, and the 10-well Sympson pilot that is drilling. And finally, before turning the call over to John, I'd like to mention a few highlights from the Bakken. Over the course of 2015, the Bakken team doubled capital efficiency and cut finding costs in half by moving to the core, reducing cycle times and lowering costs. In 2016, our Bakken drilling program will continue to focus on the core, with four rigs targeting average EURs of 900,000 barrels of oil per well. We will defer completing the majority of our Bakken wells in 2016, with the projected year-end DUC inventory of approximately 195 gross operated wells, compared to approximately 135 gross operated wells at year-end 2015. We are deferring the Bakken completions because, one, we don't want to bring on more barrels in this low price environment. Two, we have the flexibility to defer completions, since our acreage is essentially HBP. And three, it reduces CapEx, and four, it leaves us with a significant inventory of high-quality wells to complete as prices improve. This DUC inventory will have an average EUR of approximately 850,000 barrels of oil equivalent per well, and represents a valuable asset for the company that will be a strong catalyst for future growth. With that, I'll turn the call over to John.

[John D. Hart:]

Thank you, Jack. Good morning, everyone. 2015 results reflected our continued focus on cost and efficiency. Revenue for the full year was $2.7 billion and EBITDAX was $2 billion, both reflecting weakening commodity prices over the course of the year. Continental reported a net loss of $354 million or $0.96 per share for the full year 2015. Adjusted to exclude impairments, non-cash gains and losses on derivatives and gains and losses on asset sales, the annual net loss was $116 million or $0.31 per diluted share. Revenue for the fourth quarter was $575 million and EBITDAX was $420 million. Net loss for the fourth quarter was $140 million or $0.38 per diluted share. Adjusted net loss was $87 million or $0.23 per diluted share for the fourth quarter. Offsetting some of the commodity price impact was healthy production growth. Full year production came in at 221,715 Boe per day, a 27% increase year-over-year. Production averaged approximately 225,000 Boe per day in the fourth quarter. Oil production was 66% of total production for full year 2015 and 65% for fourth quarter 2015. As previously mentioned, the oil percentage of total production is expected to average 60% in 2016 due to our deferral of Bakken completions and greater capital focus in SCOOP and STACK. Longer term, we can reverse this ratio quickly as we complete our DUC backlog in the Bakken and as we deploy greater capital to the Springer and STACK in Oklahoma. Non-acquisition capital expenditures for the fourth quarter were $394 million, right in line with expectations, bringing full-year non-acquisition capital expenditures to $2.5 billion, $200 million below the 2015 budget. Operating cost performance continued to be very strong throughout the year. Our cash cost for the fourth quarter and full year 2015 came in either within or better than guidance. Production expense dropped to $3.86 per Boe in the fourth quarter, down from $4 in the third quarter. Full-year production expense averaged $4.30 per Boe, down 23% compared to $5.58 per Boe for full-year 2014. Fourth quarter G&A, excluding equity compensation, decreased by $0.27 to $1.68 per Boe versus $1.95 per Boe in the third quarter. Non-cash equity compensation dropped to $0.56 per Boe of production, down from $0.61 in the third quarter. Total cash cost, including interest, was lower at $11.47 per Boe in the fourth quarter, down an impressive 35% from full-year 2014. Combined, these low operating costs provide us with one of the strongest cash margin percentages in the industry. This provides a strong competitive advantage for Continental, not only in today's price environment, but also in a recovering market as margins will scale back up with commodity prices. The fourth quarter oil differential was $7.71 per barrel, while full year was $8.33, both within guidance. Approximately 80% of our Bakken production is now delivered to market via pipeline. As noted in prior quarters, we believe improvement in oil differentials will continue as additional pipeline capacity becomes available in the Bakken and the SCOOP and STACK contribute an increased share of total company production. The fourth quarter gas differential was a negative $0.20 per Mcf, improving 63% from the third quarter, while full-year 2015 averaged $0.34 per Mcf. Now, I'd like to turn to this year's outlook. For 2016, our capital budget of $920 million is focused on spending within cash flow. This budget is cash flow-neutral at an average WTI price of $37 for the year. As previously noted, a move in WTI prices by $5 would impact our full-year cash flow by $150 million to $200 million. We will continue to monitor the macro environment and make additional adjustments as necessary. We are a very nimble company with plenty of optionality. Many of you are looking beyond 2016 to 2017. As we've done in the past, we will endeavor to provide a longer-term view as we progress through 2016. 2017 provides significant opportunities to CLR. We will have a great deal of optionality in terms of how we begin working down our DUC inventory. As previously disclosed, we anticipate exiting 2016 with approximately gross 245 DUCs with 195 in the Bakken and 50 in Oklahoma. Obviously, commodity prices will be the primary factor in the pace and timing of completing our DUCs. This flexibility provides a wide range of possibilities in terms of 2017 maintenance capital and production. As examples, if we choose to target holding 2017 production flat at the low end of our projected 2016 exit rate of 180,000 Boe per day, this would imply 2017 CapEx of $800 million to $900 million, while maintaining a flat DUC inventory throughout 2017. As another option, if WTI prices were to increase to the low-$40s to mid-$40s, we can see – have higher CapEx in the $1.1 billion to $1.3 billion range, while still being cash flow-neutral. In this case, we would expect to increase 2017 production to an average of approximately 200,000 Boe per day, with a significantly higher exit rate. These two scenarios are based on current cost and both target cash flow neutrality. Ultimate plans for 2017 will evolve and depend on a number of variables, including commodity prices and market stability. We remain fully focused on capital efficiency and may well see enhancements to these scenarios, as we progress through the year and enter 2017. Back in November, we indicated we remain committed to maintaining our investment-grade rating. Since that time, the credit agencies significantly reduced their price deck projections, and therefore based on the changed price outlook, we and numerous other E&P companies were downgraded. Though we are disappointed to lose the rating at S&P and Moody's, I want to point out that this doesn't have a material impact on the business. The only change is to the interest rate on the revolver and term loan. We anticipate this downgrade will increase interest expense by approximately $3 million to $4 million annually. Otherwise, our credit facility structure is unchanged. The terms of our other long-term debt are also unchanged. We are and will remain in regular communication with both agencies. We will continue to manage our business in a prudent and thoughtful manner as our long-term view for operating the company is unchanged. We continue to have ample liquidity and no near-term debt maturities. At the end of December, we had $853 million of borrowings against the credit facility. Long-term debt only increased by $7 million in the fourth quarter as compared to the third quarter. As of February 19, we have $830 million of borrowings against the revolver, providing approximately $1.9 billion in available borrowing capacity under the facility. Let me point out again that the revolver is unsecured and there are no terms in the facility that would mandate collateral or a borrowing-based calculation coming into place. The revolver's sole financial covenant is a debt to total capitalization ratio of no greater than $0.65. And as of December 31, the company's debt to total capitalization was $0.58. Under the terms of the credit agreement, this calculation of total capitalization specifically excludes any non-cash impairment charges after mid-2014. I would like to conclude by commenting on all that we achieved in the past year, despite headwinds in the market. We achieved our 2015 goals to continue to deliver outstanding production results, lower operating cost and to continue striving to balance cash flow with capital expenditures. We delivered across the board and essentially achieved cash flow neutrality by the end of the year. With that, we're ready to begin the Q&A section of our call. Operator?

[Operator:]

Certainly. Our first question comes from the line of Brian Corales from Howard Weil. Your question please.

[Brian Michael Corales:]

Hey, guys. Good morning and congratulations on such a good update. I think last quarter, Jack, you talked about the potential JV in the STACK, and based on these well results, is that kind of off the table? What is your thoughts there?

[Jack H. Stark:]

Yeah. These results are pretty exceptional. And we always keep options open, but at this point, I think it behooves us to continue to develop this asset, and that's what we're planning on doing right now.

[Brian Michael Corales:]

Okay. And then just one more question on – on the DUCs, obviously you want – is there a certain price you're looking for? And especially in Oklahoma, if you're seeing kind of these improved results, is that something that you could complete sooner than maybe originally thought when you set out your plan?

[John D. Hart:]

Brian, I think we're going to be patient on that. We'll let those build up some here, but we're going to look for higher prices. I think if you look to where you would put incremental dollars, the first place you would go is to debt reduction in the DUCs, so we'll balance between those two. We're looking for – we don't have a set price, but it's somewhere in the mid $40s to upper $40s likely, closer to $50.

[Brian Michael Corales:]

Okay. Thanks, guys.

[Jack H. Stark:]

Thank you.

[Harold G. Hamm:]

You bet. Thanks.

[Operator:]

Thank you. Our next question comes from the line of Marshall Carver from Heikkinen Energy Advisors. Your question please.

[Marshall Hampton Carver:]

Yes. In the STACK, it looks like you have some more step out wells planned for 2016, this time more in Western Blaine. When would you expect those to be put on line? Would those be late in the year or could we get some results on those this spring or summer?

[Harold G. Hamm:]

We have – we have a well out to the west, it's called Anderson Halfwell, I think would be on line – would be on line in probably a couple months. We're currently drilling that well and the results will follow accordingly with normal release procedures.

[Jack H. Stark:]

Yeah, Marshall. If you look at the – there is a map in our slide deck there for the STACK area. And what you can see is about two-thirds of our wells are going to be drilled up in the over-pressured oil window this year, and about one-third will be stepping out into the condensate window further to the west. And we call it the condensate window; we're really still evaluating the limits of the oil window. As we move to the west of Boden, it did push the liquids content further west or southwest. And so, we're going to continue in our step-outs to assess this. And so, right now we think about 30% of our acreage is within the over-pressured oil window. That may grow, and we're going – through this additional drilling that you're pointing out – we'll ultimately get a handle on where the condensate window is and where do we encounter dry gas.

[Marshall Hampton Carver:]

Okay. Thank you. And one follow-up, the enhanced completions in the SCOOP, it looks like those were in the condensate window. Have you tried enhanced completions in the oil window or in the Springer or do you have any plans for that?

[Gary E. Gould:]

Yes. This is Gary Gould. And we have tested it in the oil window also. We are coming forward with the condensate type curve right now because 80% of the completion work and drilling work that we plan to do this year is in the condensate window. But as we look at the oil window, we've been testing enhanced completions there and see similar improved rates of around 30%, 35%.

[Marshall Hampton Carver:]

Okay, great. Thank you.

[Jack H. Stark:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Subash Chandra from Guggenheim. Your question please.

[Subash Chandra:]

Yeah. Quick – first one is a quick one. There's no letters of credit that have to be posted because of debt downgrade?

[John D. Hart:]

No. We – I mean we've got some very small ones. Recognize, we were only upgraded to investment grade about two, three years ago. So it hasn't been that long. You didn't see significant ones before. We don't have any significant pressure, and we haven't posted any since the downgrade. It's just not a material item to us.

[Subash Chandra:]

Got it. Okay. And my second one is, what are the infrastructure needs in the STACK area between the oil and the condensate window? Are there any limitations there?

[Jeffrey B. Hume:]

This is Jeff Hume, Subash. And there are not – there is very good infrastructure already in place, and we're very close to Cushing. So we – and we also are blessed with several refineries in the state that are out actively buying in the field. So we see absolutely no problems at all with infrastructure.

[Subash Chandra:]

Okay. Thank you.

[Operator:]

Thank you. Our next question comes from the line of Arun Jayaram from JPMorgan. Your question please.

[Arun Jayaram:]

Yeah. My first question, it seems like one of the takeaways from the earnings season – I know Marathon mentioned this on their call – is that the core or a core of the STACK is moving a bit westward. I did wanted to see, Jack, if you can maybe just talk about the implications from the Boden well in terms of de-risking inventory.

[Jack H. Stark:]

Sure. There is – there is two levels of de-risking that we need to address here. One is geologic de-risking. And there are like over 500 penetrations in the – like on our map that – underneath our acreage that allows us to essentially map out the geology of the STACK petroleum system. So from a geologic perspective, the STACK play is de-risked. So what we're doing now with the wells that we're drilling is we're essentially demonstrating the productivity and the type of productivity these reservoirs will deliver. And so, at this point, we started out here with our first Ludwig well and some of the others that have been drilled in the play and thought maybe 20%-25% of our acreage was in the oil – over-pressured oil window. Well, now we think it's 30% and it could continue to grow, as you point out, because of the high liquids content that we're seeing there in our Boden well. And so, we're still evaluating through the bit to determine just where are the limits of the oil window, where are the limits of the condensate window? But yes, you're right, we have seen the liquids-rich portion of the play, I guess you could say, moving further west than really anybody thought.

[Arun Jayaram:]

Great, great. And my follow-up just regarding just E&P capital markets. They've been relatively wide open as we think about quarter-to-date over $5 billion of E&P equity. You guys are blessed with a really high-quality set of assets. So I was just wondering about potentially looking towards equity markets maybe to – given just the uncertainty in the overall macro environment.

[Harold G. Hamm:]

Yeah. We're just not interested in diluting the shareholders with an equity offering, particularly at prices we're paying here today and what would we need money for. We wouldn't drill anymore if we had it. We just don't want to bring anything else on in this environment until we see recovery happen.

[Arun Jayaram:]

That's very helpful. Thanks a lot, Harold.

[Harold G. Hamm:]

Yes.

[Operator:]

Thank you. Our next question comes from the line of Drew Venker from Morgan Stanley. Your question, please.

[Drew E. Venker:]

Good morning, everyone.

[John D. Hart:]

Hey, Drew.

[Drew E. Venker:]

I was hoping you could just talk to the variability of the well performance used to construct that Meramec type curve.

[Jack H. Stark:]

Yeah. Yes. I can talk to it. The Meramec type curve was evaluated based on all the data that we had available to us that had daily data. So a lot of it was our wells; we had five that were our wells, we had nine other wells that we had data for also. And we were able to normalize it for lateral lengths and we're seeing good production performance there for both the 1-mile laterals as well as the 2-mile laterals And about half the wells are 9,800-foot laterals, so we feel like we've got a good representative data set there.

[Drew E. Venker:]

Okay. And do I have that right, and understanding that there's a number of non-operated wells that used to help construct that in addition to your own operated wells?

[Jack H. Stark:]

Yes. Five of ours and nine non-op that I remember.

[Drew E. Venker:]

Okay.

[Jack H. Stark:]

We're really – Drew, we're really seeing pretty impressive repeatability out here, that's one of the things that's really encouraging. And – so we've seen a lot of these plays, as they've evolved and this one probably showing the most continuity as far as repeatability as any I've been involved with.

[Drew E. Venker:]

Yeah. The results look great. On the financial side, a while back, maybe less than a year ago at this point, you talked about being interested to hedge at some point, but at prices above the curve, which I think, what you were saying at that point was something north of $70. Are you still interested to hedge at some point in the future? And I mean, taking into consideration there's been some huge productivity gains and service cost reductions, does that change the price at which you'd be interested to hedge?

[Harold G. Hamm:]

Actually, that's also a good question. What we're projecting – these prices today are unsustainable in the world and I think everybody realizes that. So we're building toward a short supply situation. Certainly when you get there, you will see a pretty good recovery of prices in the future. Will we still have the ability to over-supply the market, if people aren't disciplined, they surely could. Again, I think if it gets up, partial recovery to that range above north of $60, we'll be seriously considering hedging.

[Drew E. Venker:]

Thanks, Harold.

[Operator:]

Thank you. Next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please.

[John H. Abbott:]

Hi. This is John Abbott calling on behalf of Doug Leggate. Appreciate you taking our questions. We have a couple. Appreciate the color on 2017. But looking to that year, how should we think about decline rates across your various plays? And then second, could you speak to the variability in the oil and gas cuts in the Meramec?

[Gary E. Gould:]

I can speak to that. This is Gary Gould. As far as decline rates go for our plays, we've got about a 35% PDP decline rate for the company. And that's relatively consistent through the plays that we are on. That's for the first year, and you asked about the second year also. For the second year, that PDP decline rate goes to about 20%. And then you asked about the – I think you asked about the gas percentages for the Meramec play over time. If you look at our initial rates, you can see that right now, on a Boe basis, we're producing at about 75% oil. Overall, our EUR looks like about 60% EUR. It's just natural that has reservoirs decline and pressure, they go below the ballpoint, they do become a little more gassy, but not too much as you can see from that 75% to 60% change.

[John H. Abbott:]

I appreciate it. Thank you.

[Jack H. Stark:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Neal Dingmann from SunTrust. Your question please.

[Neal D. Dingmann:]

Morning guys. Just a quick question with your M&A. How do you think about just high-grading assets? You'll have one of the, obviously, larger asset positions now in the Bakken now, but in the MidCon. When you're looking at M&A, are you always thinking about high grading or are you just tacking on to the core positions or how do you all think about that?

[Harold G. Hamm:]

We've always looked for strategic positions within the plays that we're in, we still do that. And so, not necessarily high grading, but bolt-ons at work within the plays that we're in. So, we're always looking and hope to make some more of those.

[Neal D. Dingmann:]

Harold, what are you seeing these days on M&A? Obviously, the tremendous – it's kind of a double-edged sword on the tremendous results you're seeing in the STACK and some of your SCOOP. But how are you seeing prices these days in those parts of the MidCon versus maybe just latter part of last year?

[Harold G. Hamm:]

Well, there is opportunities out there and we have a team that's looking and working. And we've been effective in taking positions. So, not – I don't know if it's – you wouldn't call it hot, but maybe steady be the word.

[Neal D. Dingmann:]

Makes sense. And then just last one if I could. Again for any of you guys, maybe even John. When you guys look at the latter part of this year and I agree with you, Harold, that win prices do start to rebound, how do you think of your options as far as completing the DUCs versus new drills versus some financial options such as if you're bonds stay around these levels perhaps even repurchases in bonds?

[John D. Hart:]

I think we'll have a preeminent position in the industry in terms of being able to balance those. One, our bonds are – have traded out much further than they should. You've seen them strengthening over the last few weeks regardless of rating agencies. I think that was built into it. So those will come in significantly, particularly as you see a price recovery, as we move into a recovery cycle. The DUCs, we can obviously complete and bring that production on sooner, start putting off cash flow that then can go into drilling. So, as you – if you're taking a ladder and stepping up it in terms of price, the first things you'll do is start to work off the DUCs, start generating that higher level of production and cash flow and then improving your debt metrics with that and then you'll – adding rigs and those – incremental drilling will come after that.

[Neal D. Dingmann:]

Great answer. Go ahead, Harold, sorry.

[Harold G. Hamm:]

Yeah. We look at the DUCs as cash in bank.

[John D. Hart:]

They're really a savings account. I mean, we're storing all in a way that we can bring to market when we see the correct dynamics.

[Neal D. Dingmann:]

Sort of makes sense, these prices. Thanks, guys.

[John D. Hart:]

Thank you.

[Jack H. Stark:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Brian Singer from Goldman Sachs. Your question, please.

[Brian Singer:]

Thank you. Good morning.

[Jack H. Stark:]

Good morning, Brian.

[Brian Singer:]

You've highlighted a couple of options for 2017, where you stay within cash flow depending on the oil price, that makes sense why the staying within cash flow is the mantra today. Do you see staying within cash flow as a secular shift for Continental, and do you see any constraints to the pace of growth at Continental's cost of capital versus say, an entity with perhaps the lower cost of capital or greater balance sheet flexibility?

[John D. Hart:]

I think when you say secular, I think you speak to the industry. If you're asking if we think the industry is going to be more disciplined and balanced in their approach to recovery, the answer would be yes. Those that are going to last from a long-term perspective will have that balance. We will have a balance, as you've seen from those scenarios that I gave you, we can – we have become very capital-efficient and a $200 million or $300 million change can have a dramatic change in how we approach the – our assets. We don't need to outspend to a great level. So, I expect us to be disciplined, prudent and thoughtful. We're looking not only for price recovery, but stability in that price recovery as we go forward also. And was there another aspect to your question there, I'm sorry?

[Brian Singer:]

Or maybe I'll just follow up on what you said just to be clear. So regardless of how bullish one may want to get on the oil price, we should consistently and not just in this kind of down cycle, tougher credit environment, assume that Continental stays within cash flow going forward?

[John D. Hart:]

I think our expectation would be that we're going to be within or closely approximating cash flow in the near term. But we can still generate very strong results. I mean, look at the results you're seeing in the current cycle, much less as we go forward, but I think we'll be able to hold a lot of that.

[Harold G. Hamm:]

Yeah. And our spending levels don't need to be as high to grow here in the next year or two. When you look at the efficiencies from our – that we've gained over the last year as well as the DUC inventory, as you start bringing those in, those are the most cost-effective barrels that we can bring on, and we obviously have a very deep inventory that we're building out there and that will allow us to grow without – near the capital on – from a historical basis.

[Brian Singer:]

That's helpful. And on actually the point on the DUC, so really it's a question on the Bakken versus STACK here as we just look on your slide seven and the rate of returns that you would highlight in both plays. Beyond the DUC inventory which, as you say, is cash in the bank, looking at STACK versus Bakken, do you think it makes increasingly less sense to focus on the Bakken as even in the recovery scenario, just because the rates of returns on STACK are more significant or do you still see diversity as a value for the company?

[John D. Hart:]

I think diversity is certainly important, and let's be clear on the Bakken. The core of the Bakken where Continental has well in excess of 10 years of drilling competes with any asset play in North America. I mean it is a new shale, it's not an old shale, it's a very powerful and dramatic asset that we have there. So, it will compete head up with anything. That balance and that geography that we have to spread our assets gives us a lot of optionality in terms of vendor contracts or negotiations or scale and size. Continental is – if you look to the slide above – slide six, you'll see that our core asset positions are in the top end of the industry spectrum and having that diversity is something that I think is very unique in the industry.

[Brian Singer:]

Great. Thank you.

[Operator:]

Thank you. Our next question comes from the line of Pearce Hammond from Simmons & Company. Your question please.

[Pearce Wheless Hammond:]

Yes. Thanks for taking my questions. My first question pertains to the Bakken. Just curious what we should be modeling for exit-to-exit oil production declines in the Bakken.

[Jack H. Stark:]

Yes, exit-to-exit in the Bakken, we're going to be a little bit less than that 35% PDP. As we've talked about, we're going to be building DUCs from 135 at the beginning of the year to 195 at the end of the year. We expect – for the wells that we drilled this year, we're expecting to put on just 10% as that DUC inventory grows. And so, it's just a little bit shallower overall compared to our PDP decline of 35%, couple of percent flatter than that.

[Pearce Wheless Hammond:]

Okay. Perfect. Thank you. And then my follow-up. John, I enjoyed your prepared remarks, it was really helpful. And I guess bigger picture, I'd like to get your thoughts on one of the leverage metrics which is debt-to-EBITDA, which right now is a bit elevated, and I know that that's not a covenant for you, debt-to-total cap is. So I guess my question is, is that not a metric that you're focused on because you're focused on the debt-to-total cap? But what are some steps you can do to kind of bring that down? And then, if you stay in this debt-to-total cap covenant, say for the next year or so, do you start to get a little close on that covenant next year? And if the strip comes to fruition and what proactive steps, levers can you pull to help alleviate that because you've got fantastic assets to work with?

[John D. Hart:]

Okay. We always monitor that and a variety of other debt metrics, if you will. If you look to year-end, it was at, I think, 3.5 times, or a little bit above that, 3.6 times, so obviously it's come up. If you take it and run it out through the year, I mean you can run the metrics at whatever price as you want, and you push up to four, five times – around five times, so it's higher than we like. From a historical perspective, we've typically stayed around two times. We prefer to be in that range, so let's talk about what it takes to get back to that. In the case of Continental, it doesn't take $70, $80, $90, $100 oil. If you simply have a $60 or approaching a $60 pricing environment, we come down to that roughly two times, 2.25 times pretty dramatically. If you go up just $10 into the mid-$40s, which frankly is just using current prices as you've said, there's obviously a very steep contango in the price market today, so just realizing that strip, you see it starting to improve on its own. Beyond that, if we stayed in line with the prompt market, which is not what we expect or believe and not what the strip is indicating, but if you stay flat in the prompt market forever, we've obviously got tremendous assets and be it joint ventures or monetization of non-strategic assets, we've got a great deal of flexibility where we could realize cash. What we're not going to do is do something in the short term that is negative in the long term. That's why we were not accessing capital markets or those types of things because frankly, we don't need to. We've got a lot of liquidity and a lot of flexibility in that. Let me give you another little optic, and maybe I should have put it in the script, but we've modeled in, in our capital budget the $920 million. We've only modeled in 5% in cost reductions for the year. We expect and we're targeting closer to 15% to 20% for the year, as we go through the balance of the year, I should say. So, there's still a lot of flexibility and optionality in those numbers and what we're doing and we're continuing to high-grade where we're drilling and what our focus is. So, there's a lot of flexibility just in what we've done. I think it's similar to what you saw in 2015 as an example.

[Pearce Wheless Hammond:]

John, thank you for that very comprehensive and helpful answer.

[John D. Hart:]

Anytime.

[Operator:]

Thank you. Our next question comes from the line of Noel Parks from Ladenburg Thalmann. Your question, please.

[Noel A. Parks:]

Good morning.

[Harold G. Hamm:]

Good morning.

[Jack H. Stark:]

Good morning, Noel.

[Noel A. Parks:]

Just a couple things. I was wondering in the SCOOP Woodford, do you have a sense of sort of where you might be heading as sort of a max out of the proppant loading there? I was wondering if you can kind of put it in context as you look at that learning curve, sort of with where you were in the Bakken a few years ago. Are you saying now in SCOOP Woodford where you were maybe in, say, 2013 in the Bakken?

[Jack H. Stark:]

I'd say what we're finding in the SCOOP Woodford is that higher proppant works even more than what we've seen in the Bakken. And so, to give you some color on that, our standard design used to be around 750 pounds per foot as (50

[Noel A. Parks:]

Okay. And I guess thinking a little longer term – well not so long term – but the oil and gas mix across the various Oklahoma properties, in just the last month or so with gas being so weak, I think we lost about say $0.50 an M on the nat gas strip. What would say like a sustained $3 gas strip do for you, if you held oil equal sort of in your planning? Would that affect the mix of what you might be drilling in the SCOOP compared to sort of your current outlook?

[Jack H. Stark:]

Well, you know, Noel, we've got quite a lot of options through our plays here in Oklahoma. You look at STACK right now, I mean like I said, two-thirds of our activity is going to be in the over-pressured oil window here this year. And going down to SCOOP, bulk of the work is going to be more in the condensate window down there. But if we chose to and depending on where commodity prices go, we could switch to drilling a lot more Springer wells down there. You know our Springer wells, we're looking at 940 MBoe equivalent type wells there, and we basically are just – we're not drilling those right now because we'd like to wait until we have a better price environment. So, when you look at us, we just have a lot of optionality in our portfolio mix there in Oklahoma that allows us to adjust really to the changes in the commodity price. And that's been one of our strengths there. And I mentioned one other thing to you, you'd ask kind of what – I think you were asking when Gary was answering there, I was thinking this. As far as the stimulations in SCOOP, where are we at as an evolution, I think, is what you may be asking.

[Noel A. Parks:]

Yeah.

[Jack H. Stark:]

I would say, right now, we're still testing. We haven't seen the limit of what these enhanced stimulations can do. Gary mentioned that we're up to, I think 1,800 pounds, but we're actually testing some 2,000 pounds and maybe even upwards of 2,500 pounds. So we haven't hit the point of diminishing returns on the enhanced completions in SCOOP and so we're going to continue to test that this year. And so bottom line is that I can't tell you what inning we're in, but definitely we're only probably middle innings as far as that's concerned.

[Noel A. Parks:]

Great. And just one quick follow-up. With the well you drilled, that was the deepest you drilled in the Meramec yet and the SCOOP – sorry, in the STACK. Did you have any drilling challenges going to that deeper, I assume, highest pressure part of the play so far?

[Pat Bent:]

Yes. This is Pat Bent. And in the higher pressure portion of the STACK, we end up running a 9 5/8 intermediate casing string for oil stability purposes and so that strain is an incremental $500,000, so that was the primary issue, and then we were able to do that successfully.

[Jack H. Stark:]

Yeah. I really don't recall any issues in particular drilling that well compared to any of the other ones. I mean – so I think that quite frankly, we are early innings in that play as far as developing our ideal drilling method. And so we expect to see the costs that we're seeing right now is – we're looking at our cost up in STACK coming down significantly. I mean, we can see cost there coming down easily 20%-25% just based on efficiencies and knowledge gained.

[John D. Hart:]

And the team is used to drilling big wells and knows how to handle a lot of different scenarios, they do a really nice job.

[Glen A. Brown:]

Yeah. This is Glen Brown. I think in those rates, the quality of the rock that's in our STACK area is also helping us in our drilling times. We're drilling these quite a bit faster than we do our SCOOP wells, and we're working very closely on targeting and we're seeing some real step changes in terms of how fast we're drilling these wells. We basically have some of the best thickness of STACK, we have some of the best pressure in STACK, and we have the best rock in STACK. And I think that's the reason we're three times as good as the rest of the STACK. So the drilling just comes along with being in the best rock.

[Noel A. Parks:]

Great. Thanks a lot.

[Jack H. Stark:]

Thanks, Noel.

[Operator:]

Thank you. Our next question comes from the line of Gregg Brody from Bank of America Merrill Lynch. Your question please.

[Gregg William Brody:]

Hey guys. Most of my questions have been asked and answered. But just one for you. In terms of your midstream and your pipeline and sort of all your transport, is there an opportunity to extract some value there today? And also, are any of your commitments there heading up against any thresholds right now with the oil production this year?

[Harold G. Hamm:]

We're actually, it probably would be if we wanted to tackle that business, and we'll just not – that's not our focus, and so we're actually making the arrangements out there in the field. And so, I don't believe we're ever going to go there.

[Jack H. Stark:]

We're not looking to enter the business if you're referring to do. We have assets that we could monetize. We've probably got $100 million or $200 million in tanks and various other things that we could do. But they're very strategic to us, and benefit the company from an equity ownership precision side and give us a lot of flexibility and growth typefaces also. So I think we'll probably hold on to those.

[Gregg William Brody:]

In the places where you have minimum volume equipments, are you above those thresholds today?

[John D. Hart:]

Yeah...

[Gregg William Brody:]

(57

[John D. Hart:]

Yeah. Gregg, they're not significant. If you look in our 10-K, there's a commitments table in there, that will give you right after MD&A, gives you the various pipeline commitments. They're probably, what, 20% of our total production, maybe less than that, not significant in that term. Because of the size and scale that we have in our assets, they need us and want our business in many ways, so we don't necessarily have to have the – be as – the firm commitment.

[Gregg William Brody:]

I'm staring right at it right now. Thank you.

[Jack H. Stark:]

Thanks, John.

[Gregg William Brody:]

Thank you guys.

[John D. Hart:]

See you, Gregg.

[Operator:]

Thank you. And this does conclude the question-and-answer session of today's program. I'd like to hand the program back to Warren Henry for any further remarks.

[J. Warren Henry:]

I just like to thank everyone for again, for joining us this morning, I know, it's been a very, very busy week in last couple of days, and I'd like to just say, we'll look forward to reporting another strong quarter to you in early May. Thank you very much.

[Operator:]

Thank you ladies and gentlemen for your participation in today's conference. This does conclude the program, you may now disconnect. Good day.