Cimarex Energy's (XEC) CEO Tom Jorden on Q4 2015 Results - Earnings Call Transcript

| About: Cimarex Energy (XEC)

Cimarex Energy Co. (NYSE:XEC)

Q4 2015 Earnings Conference Call

February 17, 2016 11:00 ET

Executives

Karen Acierno - Head, Investor Relations

Tom Jorden - Chief Executive Officer

John Lambuth - Senior Vice President, Exploration

Joe Albi - Chief Operating Officer

Mark Burford - Chief Financial Officer

Analysts

Dan Guffey - Stifel

David Deckelbaum - KeyBanc

Drew Venker - Morgan Stanley

Jeanine Wai - Citi

Matt Portillo - TPH

Jason Smith - Bank of America Merrill Lynch

Michael Hall - Heikkinen Energy Advisors

Operator

Good day and welcome to the Cimarex Energy Fourth Quarter and Full Year Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Ms. Karen Acierno. Please go ahead.

Karen Acierno

Thank you and good morning everyone and welcome to our fourth quarter and full year conference call. In addition to last year’s results, today, we will be discussing our 2016 capital plans, which were released separately yesterday afternoon. An updated presentation has been posted to our website. We will be referring to this presentation during the call today.

As a reminder, our discussion will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discussed. You should read our disclosures on forward-looking statements in our latest 10-K and other filings and news releases for the risk factors associated with our business.

So today’s prepared remarks will begin with an overview from our CEO, Tom Jorden, followed by an update on our drilling activities and results from John Lambuth, Senior VP of Exploration; and then Joe Albi, our COO, will update you on our operations, including production and well costs. Cimarex CFO, Mark Burford, is also present to help answer any questions.

So with that, I will turn the call over to Tom.

Tom Jorden

Thank you, Karen and thanks to everyone who is participating in today’s conference. We sincerely appreciate your interest and look forward to your questions during the question-and-answer portion of the call. On the call today, John will give a rundown of our recent results and update you on some of the delineation that we have underway in 2016. Joe will provide an operational overview.

I would like to kick off the call with some overview remarks in our direction in 2016 and beyond. During 2015, we put a lot of energy into long-range planning and we developed capabilities for running detailed iterations on current and future year’s CapEx, cash flow and balance sheet configuration. We scrubbed our assets and developed net asset value models that help us to fully understand our upside and plan accordingly. Today, we are making decisions for 2016 with a close eye on 2017, 2018 and beyond. Cimarex is better positioned for the future by slowing down a bit, preserving our cash and assets and living within our means.

Our focus is on preservation of our assets and balance sheet. We don’t have any special insight on when or how commodity prices will recover. We do know that we will probably be as surprised by the recovery as we were by the collapse. When prices recover, Cimarex will be ready and will be stronger and healthier as ever. We have never been more bullish on our assets, our inventory and our organizational capability. Our Delaware Basin and Meramec Woodford assets are top tier. We continue to be pleased with our well results and associated returns on investment.

On the call today, you will hear updates on our Wolfcamp spacing pilots and the implications for future development. We continue to be extremely pleased with our Wolfcamp well performance and have room to run in achieving further performance improvements. You will hear an update on the Meramec Woodford spacing pilot that is underway in Cana. We are testing a combined 19 wells per section in the Meramec and Woodford. The Meramec continues to surprise to the upside. We are currently flowing back Woodford spacing pilots that are testing 10 and 12 Woodford wells per section. Results are very encouraging. Furthermore, our improved Woodford results are showing remarkable consistency across the Cana core. In both the Delaware and Woodford Meramec, long horizontal wells are an increasingly important part of our story and our assets are well configured to allow for them. We have a manageable lease exploration issue and we will preserve all of our prime acreage.

In spite of the downturn of activity, we are emphasizing our core strengths in idea generation and innovation. Our teams are hard at work developing new plays and new concepts. During the downturn of 2009, our activity level dropped from 43 operated rigs to 3. At that time, we challenged the organization to be innovative, creative and to find ways to make a living in spite of the downturn. We were not victims. During 2008, we developed plays that were going to carry us in the ensuing years and are still among our core programs today. In 2016, our challenge to organization is to do it again. We are built for these times however difficult they may be. We will make the tough decisions around capital investments and activity levels. We will remain disciplined and preserve our assets and the deep inventory that is our future. We will also seek to build new things and to take advantage of this downturn. No one is hanging their head at Cimarex. We are hard at work to control our own destiny.

I recently heard a CEO describe some advice that one of his board members have given him. The board member was a retired military officer who told the CEO that he had always told his troops that, when the map doesn’t match the terrain, go with the terrain. Here at Cimarex, we are going with the terrain. During 2015, we increased our rig count to a high of 12 rigs, with an original plan to keep 12 operated rigs throughout 2016. As the year wore on and the commodity outlook continued to worsen, we determined that a 12-rig program was no longer prudent. Although we have the inventory to justify the higher activity level even at current prices, we have decided to slow down and preserve our cash on hand. Production growth will have to take a backseat to flexibility and balance sheet preservation.

Our focus is on a multi-year outlook. We currently have 11 operated rigs running and will be decreasing our rig count to 4 rigs in the coming months. Our 2016 program is designed to preserve our assets on leasehold and finish out some delineation and spacing pilots that are underway. We plan to invest between $600 million and $650 million in exploration and development. The range of investment is driven by timing of completions in one of the projects currently underway, the Woodford infill well in the eastern core of Cana. Whatever we do not spend in 2016 will be pushed into early 2017. We will also continue to delineate the Meramec drill spacing tests in the Wolfcamp and the Delaware Basin and hold leasehold.

In the fourth quarter of 2015, we were impacted by severe weather events and took direct hits at both the Western Delaware Basin and in our core Cana field. Furthermore, a planned outage in Delaware Basin added to our problems. I cannot overstate how pleased we were with the response to these events by our organization. Although they had a significant impact in our production volumes, our teams worked valiantly and safely in extremely hostile conditions in order to restore our production and find creative workarounds to market interruptions. These extraordinary actions don’t always evidence themselves in top line reported production numbers, but they humble us and make us deeply proud to be part of an organization that is so dedicated and focused.

With that, I will turn the call over to John to provide further details on our program.

John Lambuth

Thanks, Tom. I will start with a quick recap of our drilling activity in the quarter before getting into some of the specifics of our latest results and more color on our 2016 plans. Cimarex invested $191 million during the fourth quarter on exploration and development. This brought the total to $877 million for the full year. About 55% was invested in the Permian region with the rest going toward activities in the Mid-Continent region. Company-wide, we brought 65 gross, 28 net wells on production during the quarter, which brought the total for 2015 to 219 gross, 99 net wells.

Cimarex continues to push the envelope on well completions. In the Permian, we completed 2 upper Wolfcamp wells in the fourth quarter using a larger stimulation. As you can see on Slide 14 of our presentation, these wells have seen a 34% higher cumulative production in the first 120 days versus the previous upper Wolfcamp wells. In fact, one of the wells, Mine That Bird 38 Unit #1-H had an average 30-day peak production rate of 2,020 barrels of oil equivalent per day, of which 51% was gas, 30% -- excuse me, 51% oil, 30% gas and 19% NGL, a record IP from a 7,500-foot Upper Wolfcamp lateral in Culberson County.

As discussed previously, we spudded downspacing pilot in the upper Wolfcamp and Culberson County in the fourth quarter. Drilling on these wells will be finished this month with completion scheduled to begin in April. First production is expected by the end of May. This 6-well, 7,500-foot lateral pilot will test two different spacing designs, one testing 8 wells per section, while the other will test 6 wells per section. Both will be drilled in a staggered pattern. The larger completion I just discussed will be used on this pilot.

For the rest of 2016, the vast majority of the capital that we will spend in the Permian will be earmarked for acreage obligations across our Wolfcamp position in both Culberson and Reeves County. Part of this obligation drilling will include 6, 2-mile long infill wells in Reeves County. These infill wells are located next to our Big Timber well, the best Wolfcamp well we have drilled in Reeves County. Similar to our Anaconda pilot, these wells will be drilled using a stack staggered pattern, resulting in equivalent of 12 wells per section. We currently have 6 rigs running in the Permian, with one of them drilling a saltwater disposal well in Culberson County. By June, we will be down to 2 rigs for the remainder of the year.

Now, on to the Mid-Continent, you will recall that we began drilling on the Cana-Woodford row 4 infill development program in the fourth quarter of 2014. Completions on the seven sections are now finished and all 57 gross wells are producing. Cimarex operated two of these sections. Typical development in the Woodford calls for eight new wells in addition to the parent well on a section. The Armacost section was infilled with nine additional wells, while the Philip section was infilled with 11 new wells. For the Armacost section, the average 30-day peak production was 9.1 million cubic feet equivalent per day, 61% gas, 8% oil, 31% NGL. And the Philips wells produced an average 30-day peak rate of 9.3 million cubic feet equivalent per day, 54% gas, 13% oil, 33% NGL.

As you can see on Slide 20 of our presentation, these increased density infill sections are performing very similar to previously infill Woodford sections with only eight new wells, a very encouraging result for us. In the fourth quarter 2015, we commenced drilling another Woodford infill well in the East side of the core. This development covers six sections, of which Cimarex again operates two sections. The entire infill project consists of 50 gross, 23 net wells. Depending on the timing of completions, something that will be worked out with our partner, production from this East Cana development was expected to come online as early as October or perhaps as late as the first quarter of 2017. In our emerging Meramec play, we now have production data on 17 operate at 5,000 foot laterals. In addition, our second 10,000 foot lateral in the Meramec has been on production since early October. This well, called the Vessels 1H-3526x have a 30-day peak IP rate of 14 million cubic feet equivalent per day, including 791 barrels of oil per day.

Page 22 of the presentation illustrates the average uplift we have seen from the two long laterals versus the 5,000 foot laterals drilled to-date. We have outperformed the shorter laterals by 69% within 120 days. While we are very encouraged by the initial uplift in IP that we are seeing in these 10,000 foot laterals, we will be carefully monitoring the decline profile in order to determine the ultimate EURs for these long lateral wells.

To better understand the multi-zone potential for this area, we have designed a down-spacing pilot which commenced drilling in the fourth quarter 2015. See Slide 23 for an illustration of this design. Due to the commodity price environment, this pilot has been downsized, will now consist of eight new wells to be stacked and staggered in both the Meramec and Woodford formations. The spacing at the Meramec will be the equivalent of 10 wells per section made up of five upper and five lower staggered Meramec wells. The Woodford will be drilled with our standard nine wells per section development plan. Drilling should be finished by mid-April with first production expected late in the second quarter. Once drilling is finished on the pilot and infill sections, we will be focused on holding our Meramec acreage. Since late 2014, we have added 12,250 net acres in the Meramec at an average cost of $1,650 per acre. We will need to drill approximately 40 to 45 wells over the next 3 years in order to HBP our position. In 2016, we will drill 12 operated wells to hold this acreage position, with 10 of the 12 wells being 10,000 foot laterals. We currently have five rigs operating in the Mid-Continent region, with plans to go down to one rig by July of this year.

With that, I will turn the call over to the Joe Albi.

Joe Albi

Well, thank you, John and thank you all for joining us on our call today. I will touch on the usual items, our fourth quarter production, our Q1 and full year 2016 production outlook and then I will finish with a few comments on LOE and service costs. Our fourth quarter total company net equivalent production came in at 985.7 million a day, up 4% from the 949.5 million a day that we posted in Q4 ‘14 and within our guidance of 0.98 Bcfe to 1.01 Bcfe per day. Late in the quarter, as Tom mentioned, winter weather and facility disruptions negatively impacted our production by approximately 30 million cubic feet a day equivalent, with the majority of that occurring in the Permian. Late December winter storms caused significant downtime in not only the Delaware Basin, but also impacted our Cana production as well, albeit to a lesser degree. When we adjust for the estimated impact of the weather and the facility downtime, we would have exceeded the upper end of our guidance by more than 5 million a day. With Q4 now in the books, our full year 2015 equivalent production came in at 985 million a day. That’s up 13% over our 2014 average of 869 million a day.

During Q4, our Permian equivalent production averaged 520 million a day. That’s down 42 million a day from Q3 ‘15. But as I mentioned, a significant portion of the decrease was a result of not only the – was a result of the weather and facility downtime, but we also completed fewer Permian wells during the latter half of the year than we did in the first half as we talked about in our previous call. As expected, with our Cana-Woodford wells coming online, we saw a very nice bump in our Q4 Mid-Continent production, with our Mid-Continent volumes coming in at 461 million a day. That’s up 14% or 56 million a day from the 405 million a day that we reported just prior in Q3.

For 2016, with a number of moving parts, the most sensitive of which is the timing of our 2016 completions. We have issued full year total company equivalent production guidance of 890 million to 930 million equivalents per day. With our focus on preserving our assets and protecting our balance sheet and the low price environment we are in, we have opted to slowdown and more consistently spread out our completion activity throughout the year. As John mentioned, we also find ourselves needing to coordinate the timing of our Cana-Woodford completion activity with the completion timing of our offset operator. As a result, there is considerable variability in the inventory of uncompleted wells that we will have on the books at the end of the year.

As we best can project at this time, we anticipate and we have modeled that our Cana infill fracking operations will begin in late the third – late third to fourth quarter and continue into 2017 with first production from the project not hitting our books until early 2017. This program represents a lion share of our 2016 Mid-Continent activity, consisting of 50 gross and 23 net wells. With our current modeling, we expect to see first production from approximately 50 gross or 16 net Mid-Continent wells during ‘16 and that’s down from 134 gross or 39 net wells that we completed in 2015. With the anticipated Cana infill completion delay, we expect to exit the year the 57 gross or 24 net wells awaiting completion, hence moving associated production for those wells into early 2017.

In the Permian, we also plan for a slower place of completion activity, which will likely only require us to utilize just one completion crew the majority of the year. We are forecasting approximately 31 net Permian wells to come online in 2016, that’s down about half of the 60 net wells that we completed in 2015. As we progress through the year, we project a number of Permian drilled and uncompleted wells to increase to approximately 18 net wells by mid-year and then drop off to just six net wells by the end of the year, primarily a result of us dropping to the two rigs that John mentioned in the Permian in the middle of the year.

I want to take a moment to make a special point that a quick glance at our 2016 full year guidance could very easily imply a decline in our 2016 exit rate. What’s not so easy to see is the forecast of production increase associated with the delayed Cana infill programs back to back completion activity in early 2017, which along with a handful of Permian carryover completions is forecasted to bring our total company production back up to Q4 ‘15 levels by as early as Q2 ‘17. It’s all about the timing of our completions. As far as our Q1 total company production is concerned, incorporating anticipated Permian pipeline and facility curtailments of about 30 million a day for the first quarter, our projected guidance for Q1 comes in at 925 million to 955 million a day.

Jumping over to CapEx, with our production group’s continued focus on trimming operating costs, our Q4 lifting costs came in at $0.85 per Mcfe. That’s in line with our guidance of $0.77 to $0.87 and was down 19% from the $1.05 that we posted in Q4 ‘14. For the year, our 2015 lifting costs came in at $0.83 per Mcfe, that’s down a respectable 23% from our 2014 average of $1.08. As we look forward into 2016, our full year lifting cost guidance range of $0.80 to $0.90 per Mcfe takes into account our regional forecasts of production mix as well as the variable nature of work over expenses. You may have also noted that our Q4 ‘15 transportation and processing expenses came in at $0.58, so slightly above our guidance range of $0.45 to $0.55. As I mentioned, our current production modeling forecast a slowdown in our completion activity during the year, which resulted in a one-time accrual of approximately $8 million for anticipated minimum volume agreement shortfalls, which increased our reported cost on a non-recurring basis by approximately $0.09 per Mcfe.

We have made great strides cutting our LOE and we will continue our efforts to reduce them further. As we mentioned last call, the important by-product of our LOE reductions is the additional funding we are providing our drilling program. Our Q4 ‘15 average monthly LOE came in at $25.7 million a month and that’s $5 million below our Q4 ‘14 average of $30.7 million a month. But if we average over 12-months time period, has freed up nearly $60 million that we can direct to our drilling program.

A few comments on our drilling and completion cost. Although we continue to push hard for further cost relief, any cost reductions we have seen have been small, single-digit reductions and modest in nature. That said, we continue our focus on operating efficiencies. On the drilling side, we have high-graded our rigs. We are fitting out each and every service. We are consolidating our equipment and resources everywhere we can. All the while we are staying focused on reducing drilling days. On the completion side, we are focused on optimizing the cost of water sourcing by more efficiently fracing our wells, in particular, when we are completing multi-well pads. The bottom line is that while we continue to experience – experiment with various frac designs, our generic well AFEs have remained relatively flat.

Our current Cana core one-mile lateral Woodford AFE continues to run in the range of $6.6 million to $7 million. That’s unchanged from last call. While in the Meramec, our current one-mile lateral AFE is in the range of $7 million to $7.4 million. That’s also unchanged from last quarter. In the Permian, as we have mentioned last call, we have made great progress with our drilling efficiencies, cutting our Wolfcamp two-mile lateral spud to rig release times down 20% from 35 days in 2014 to 28 days in 2015, with a record of 20.5 days. We are accomplishing similar drill time reductions in our one-mile lateral Bone Spring and Avalon program as well cutting average days from spud to rig release 35% from 23 days in ‘14 to just ‘15 in Q4 ‘15. We continue to get more done with fewer rigs. And with all that, our current two-mile lateral Wolfcamp AFE is running $10.8 million to $11.6 million. That’s flat again to the figures we quoted last call.

So in closing, we had another great quarter. We fought up significant Q4 downstream weather – downtime to stay within guidance and provide us with a strong springboard for production in 2016. We posted solid year-over-year production gains over 2014. We have made significant strides cutting our LOE. Our drilling group stays focused on cost reductions and efficiencies. And as an organization, we remain vigilant to keep our cost in check, protect our assets and optimize our investment program results.

So with that, I will turn the call over to question-and-answer.

Question-and-Answer Session

Operator

Thank you. [Operator Instructions] And our first question will come from Dan Guffey of Stifel. Please go ahead. Mr. Guffey, please go ahead. Your phone maybe muted.

Dan Guffey

Sorry about that. Good morning, everyone.

Tom Jorden

Good morning.

Mark Burford

Good morning.

Dan Guffey

In the past, you guys have conveyed budgetary snapshot of the current environment and the company does remain flexible. I guess key question here is, at what price would you want to bring rigs back, obviously, with the extreme volatility in crude, it may make that decision a little more cumbersome? But just curious when you think you would add rigs back since you do have some of the lowest cost production throughout the U.S.?

Tom Jorden

This is Tom. That’s a great question. Mark, I am going to – I will pass that to you. We have run tons of models and it’s hard to make a definitive statement. I will say this so before Mark comments, we remain highly flexible. And if we see daylight, we are going to run for it. Obviously, in building a company and preserving a balance sheet, you can have all kinds of optimism, but you can’t run a company on that optimism to the extent that you are not preserving your balance sheet. But Mark, you know how to answer it?

Mark Burford

Dan, surely what Tom referred to is we are on the two primary concerns we have right now watching our return on our investments making sure we get adequate return which isn’t the highest – isn’t the biggest concern more was not preserving our balance sheet. So, we have cash flow sufficient to really support our larger program, which we are really trying to constrain our investment to make sure we preserve a very strong balance sheet, preserve our cash position and a better way to do this. So, I think if you saw price environment settling in around $45 to $50, you could probably see us have the cash flow supporting a larger program. But at the low $30 environment we find ourselves in and that’s where we are constraining our investment to the extent we are, but there is – it probably have to be some clarity – certainty around that $45 to $55 for us to see that to make some upward adjustments in our investment page.

Dan Guffey

Okay. I guess, are there any limiting factors in terms of how quickly you could add whether that be personal or infrastructure? And then I guess, what area would your first few incremental rigs target should we get to that $40 to $50 environment?

Joe Albi

Well, this is Joe. As far as our organization is concerned, we can act quickly. And depending on where we are drilling, if it’s in and along our existing infrastructure, that shouldn’t be a problem. You got to remember that we had a bigger plan scheduled and modeled as far as our organizational activity and we just paired back from it. So, getting back on the track should not be that difficult for us. We took a rig out of the yard. We have got to ask that question last year and we took a rig out of the yard that on its first wells start setting records for us. So, we are not terribly concerned about our ability to ramp up. And I would anticipate that our first place to ramp up would be the Permian.

John Lambuth

Yes, this is John. Without a doubt, we are ready to go. Our Upper Wolfcamp wells in Culberson, as I talked about earlier, are really coming in performing very well. And we’d love to get back to drilling into that program beyond just the spacing pilot I talked about. Our long lateral Bone Spring play, up in White City, is very, very strong economics. And even part of our Woodford development in the Eastern core, which is more liquid-rich, especially as we look at it from a long lateral perspective, which our acreage allows us to do looks pretty attractive to us, but we would like to see a little bit more encouragement from the commodity price before we want to go and deploy capital in those programs.

Tom Jorden

Yes. And I just want to finish your question, but I don’t want to throw a marker down that’s $45 oil price. If we see a recovery in oil price, it looks better and better to us. So, I would even say if prices get north of $35 and our outlook is stronger, we are going to look at it. I don’t want to throw any particular number down and say, that’s the number. We have the flexibility. We have the balance sheet to do it. And it’s going to be what our vision is. I mean, if there were some structural changes in all markets and the reason for long-term optimism, we would be prepared to act to that.

Dan Guffey

Okay, great. Thanks for the details. Last one for me, can you guys discuss if you still you have reached or surpassed the productive and economic limits of enhanced completions across your various areas throughout the Permian and the Mid-Con?

John Lambuth

Well, this is John and the very simple answer is no. In no way that we feel like we have reached the limits. We constantly are debating entirely about all the different components that go in at our frac design. And quite frankly, I am constantly amazed how certain tweaks lead to even better and better wells. So no, we are not at all feel like we have reached a point where we can get even more reserves out of these laterals. And quite honestly, that’s some of our charge right now, given the environment we find for every dollar we invest in those wells, we need to get more out of those wells. And so far, I have been very pleased and that we have been able to achieve that with a number of our programs.

Tom Jorden

Yes. And I want to – this is Tom, I want to follow up to that. John and I started off first thing this morning at 7 o’clock in my office arguing about just this thing, not arguing with one another, arguing the point that one of the nice things about having assets and through the most active prolific areas of the country is there is a lot of activity. And we study our competition really hard. It’s pretty important if you are going to have an innovative culture you can’t have and needs to be invented here mentality. And so we are always looking to see what others are doing. And I think we have a lot of room for improvement, I would say in both our corridors, the Delaware Basin and Meramec. There is lots of things others are doing that, yes, we have opinions on, but at the end of the day, some of this is just trial and error and we need to try some things.

Dan Guffey

Thanks for the color, guys.

Operator

Our next question will come from David Deckelbaum from KeyBanc. Please go ahead.

David Deckelbaum

Good morning, Tom and everyone. Thanks for taking my questions.

Tom Jorden

Yes, good morning.

David Deckelbaum

Just to follow up on all the commentary. Tom, in your opening remarks, you said you are looking very closely at ‘16, ‘17 and ‘18 as I guess putting some color around that, is it looking closely at what sort of goals would you like to achieve at the field level, looking closely at what your debt metrics are, looking closely at how much cash you have or a production growth scenario?

Tom Jorden

Well, you kind of run through the gamut there. We are not changing our logo. So we can take that one off the table. As we look ahead, I think the industry is having a sobering reset and I would love to sit here in the call, put lipstick on and say, you know what, it’s one thing. But as you look ahead in running a company, we have to look at the ins and outs of cash flow balance. And so we look into what – I said in my opening remarks, we spent a lot of time last year looking at our assets and looking at the future drilling inventory and the value that adds. And we have made a tremendous amount of progress on our flexibility and our ability to do real-time modeling of future increases in price, future increases in activity and actually modeling the impact that has fully looking at our cash flow and our balance sheet. But when you do that, one of the reasons that we are doing that is because if prices don’t pick up at any point, we want to make sure that Cimarex stays healthy and stays competitive. And we don’t want to put ourselves in a situation where we have lost our flexibly. So inherently, that modeling is kind of a downside model. It’s really easy to run an upside model. But you have to kind of plan of the downside. And so we are – as we look ahead to the next few years, I will say that if things don’t materially improve over the current strip, Cimarex will be just fine. We will be healthy financially and we will be in a position where we attempt to throttle into that future without increasing debt. But if things increase, if commodity prices pick up, we are ready to roll. I know I am not giving you – I am not giving you detailed answer on what our 2017 and beyond model looks like, but we are making decisions to keep Cimarex competitive and to preserve our assets. Mark, do you want to add to that?

Mark Burford

Yes. Let me try, Tom. When you look at the different scenarios David, it’s obviously some bookings were using strip influences a lot of our thinking right now in the four strips in the low 40s through ‘17 and only $45 by ‘18 our recent stripping holding. And looking what our activity levels could be at those different price decks preserving our balance sheet strength and seeing what fits within that cash flow without really having occurred in preserving some portion of our cash balance and not incurring incremental debt what we can look like into those future years. And it is current strip environment, low-40s, it’s been 30s are challenging for us to find a [indiscernible], with our cash flow can support our pace of development. So there are lot of iterations we are running all the time, looking at different sensitivities on different programs. And then given – as Joe remarked in his comments even for this year have been impacted to a thorough completions can have a very big impacts on our timing of our production thing. So we are running on iterations just looking at what the outlook could be for this year and for the years out.

David Deckelbaum

I appreciate all the clarity around that. There is one more if I might, I know John you reminded all of us about LOE might not be appreciating the amount of production that can come on from 50 Cana wells and the infill towards the end of the year beginning of next. And you said 2Q of ‘17 could be back up to the levels of 4Q ‘15 conceptually. You are running four other rigs total, much of that is for HBP and acreage. So as you think about going into 2017 and 2018, is – would future rig activity or incremental rig activity be devoted to doing a very large pad our multi-section developments where we would have this sort of persistent lumpiness until things smooth out where you have a larger rig fleet that’s called up everything?

John Lambuth

Yes, this is John. I think it’s safe to say that when we reach that point that we want to get back towards true development drilling, then certainly that’s going to lead towards that high intensity rigs and pads and so forth. But we just don’t know at one point we will be back there. Here is what I know. I know for this year and going forward, our main goal, as Tom alluded to, is both the balance sheet and more importantly protecting investments we made in the acreage that we picked up in both the Anadarko as well as the Permian Basin. We have wonderful acreage and we have gotten it at a very attractive price and essentially for this year’s program, as we go up to the end of the year, that’s where our capital is going to be geared towards is preserving that acreage position so that we are in a very good position. Whenever the time is right, then go back to that full scale development, when that will be, I can’t tell you at this point.

David Deckelbaum

Okay. I appreciate all the answers guys. It’s all for me.

Tom Jorden

Thank you.

Operator

Our next question will come from Jeanine Wai of Citi. Please go ahead.

Jeanine Wai

Hi, good morning everyone.

Tom Jorden

Hi Jeanine.

Jeanine Wai

Can you talk a little bit about your forecasted out-spend for 2016 on whenever price deck you are using, it sounds like the strip, there appears to be a fair amount of non-D&C spend that might be driving some of the out-spend?

Mark Burford

Hi, Janine, this is Mark here. Yes. So in our 2016 out-spend about $600 million, $650 million of capital using a recent strip price around $34, $2.20 gas. We are looking at coming in the year with $539million of cash. We are looking exiting the year somewhere around $400 million of cash add back to ‘16.

Jeanine Wai

And can you give a little bit of clarity on what that non-D&C is?

Mark Burford

Yes. So the non-D&C drilling is comprised of about $35 million. We are targeting for the lease-hold acquisition, about $120 million roughly for capitalized overhead, it was about $40 million for production capital or at least for our production group capital for the re-completion and well maintenance, eight wells.

Jeanine Wai

Okay, great. And then I know that you have mentioned that IRR is not the only factor in determining activity for this year, but can you give us a little sense of whether you have an after tax IRR hurdle in this environment or kind of what the after tax returns are on some of the plays that you mentioned that are performing very well in the current environment?

John Lambuth

Well, this is John. And yes, we always have on our way to return hurdles. They are a little bit challenging right now. What we find ourselves – I guess what I find myself doing, there has been a lot of time looking at just flat price returns, I just don’t spend much time looking at strip right now. And then we look at those flat prices and we ask ourselves, is this a good investment. Especially these wells we are drilling to hold acreage. And in this environment, it’s tough, I will admit. But when we look at that and look at the future potential of that section we are holding, we still feel like we are making a very good investment in drilling those wells. So right now again, we definitely look at the IRR and quite frankly, that means some of the acreage that we have will not be held because no matter what scenario, whatever flat price I look at, it’s hard to envision how holding a certain set of acreage is in the best interest of Cimarex. That said, we have a lot of good acreage to hold there on and I am very pleased with that.

Tom Jorden

Janine, this is Tom. We run everything currently down to around $30 NYMEX oil and $2 NYMEX gas held flat forever. So those are index prices, and then we will deduct whatever market deduct to get back to the wellhead. And we would like to see our cost of capital are better at that flat price. And then we will also look at the strip. And let me just answer your question this way. If we were forced to increase activity and we had an A-tax 25% hurdle rate. We have lots to do in our portfolio. If we weren’t tasked with holding acreage and we can just go drill at will and there were no other considerations, when we look at these long laterals in the Wolfcamp, the long laterals in the Cana, Meramec play, we have lots of them that generate, what I would say, are acceptable returns at current strip. But as John said, we have a lot of considerations currently. We don’t think prices will stay here forever. We have some outstanding acreage that we would like to hold, not all of which can be developed with long laterals. We have partner considerations. And then we also have some science that we want to get done that will really set up the future. So it’s a balancing act. One thing that we will not do, one thing we will absolutely not do is liquidate this company because we are in a $30 oil environment. So we are going to make judgment calls as we see fit.

Jeanine Wai

Okay, great. Thanks very much for taking my question.

Operator

Our next question will come from Drew Venker of Morgan Stanley. Please go ahead.

Drew Venker

Good morning everyone.

Tom Jorden

Hi Drew.

Drew Venker

If you could provide some clarity just on that you are targeting a leverage ratio or if you are still thinking about spending the remainder of the secondary offering proceeds or how you are setting the budget really?

Mark Burford

Drew, this is Mark. As I mentioned, what we are looking at planning for ‘16 right now, with our current $600 million, $650 million of cash, capital plan for ‘16 and the recent strip price forecast for cash flow, we think we would use up from December 739 million we exited ‘15 with net debt of ‘16 out $400 million of cash in the balance sheet. So no, we didn’t expect to use remainder of the proceeds in ‘16 and we are going to see how the environment flattens out before we get that activity further, but no, we do not plan to use in ‘16 and then even in ‘17 we are still looking at different scenarios now and what pace will be in ‘17.

Drew Venker

Mark is there a target leverage ratio or is that not really a primary consideration?

Mark Burford

Drew, we really have one financial covenant, which really in our credit facility which the debt to cap covenant, which is limited to debt cap of 65% and we exited the fourth quarter of 35%. And going into ‘16, we don’t see us having any issue of that covenant, even with potential future impairments, which are likely with the fact that prices are continuing to still – drilling 12 months average is still declining through ‘16, but we will have to watch that metric. Our debt to EBITDA metric typically would have been 1.5x or less, but with – in our dropping commodity prices, that metric is obviously more challenging and the exit year 12-month price debt-to-EBITDA of 1.9x. Going into ‘16, we expect that probably likely will go into low 3s or so into ‘16 with EBITDA still falling lower prices.

Drew Venker

Okay, alright. That’s helpful color.

Mark Burford

Because they are in fact thrilled, we have a covenant that we have to watch carefully, Drew, with the rest of the covenants. We just – we were projected as basically we are not in fact expect incurring incremental debt in this environment and indeed in the future for some time. We expect to just have the $1.5 billion of senior secured notes outstanding. We don’t expect any bank borrowings in the near future.

Tom Jorden

Drew, it’s Tom. I want to be clear and I think I have been, but we have actually made this tactical decision to try to keep as much cash on our balance sheet so that we are well positioned when this situation turns around. We think that the best activity level for Cimarex in 2016 is preservation mode. We want to make sure we preserve our assets, we preserve our obligations and we preserve our flexibility. But our goal is to keep as much cash as we can on the balance sheet as we look ahead so that we are well-positioned to strike when we see some daylight.

Drew Venker

Right. Yes, that all makes sense, I think. I guess, and along that vein, does it make sense to layer on hedges albeit I realized the forward curve is not really where you would like it to be but maybe for you and for 2017? Is that – does that make sense strategically?

Tom Jorden

Yes, Drew, we have for sometime now. We are working towards having a quarterly progression in our hedging program. And we did take steps in the first quarter, hedged 40 million a day for 15 months for second quarter of ‘16 to second quarter of ‘17. And that was a layer that we will put in is targeting on about 10% of our four production roughly in that neighborhood. And we look at it again. And we were targeting 4,000, 5,000 barrels a day of oil would be our target for the first quarter. Other, as you mentioned a forward strip in oil prevented us from taking that step on oil, but each quarter, we are going to look at that forward projection on our volumes and look at clearing maybe 10% on our volumes each quarter and over a period of time, when you hope to get to about 50%, our volume covered. But we have been inhibited by low oil price for taking that step on oil.

Drew Venker

Okay. If I could circle back on the new Wolfcamp A completions, is the plan to implement that new style on the rest of your program? I know you said you would use it on the density pilot, but all of you are drilling in 2016, is that applicable to the Wolfcamp C and D as well?

John Lambuth

This is John. Well, it’s certainly applicable to come up with the next new innovation on it, yes, I mean, we plan to use that current design on that spacing pilot. We have a little bit different design for the lower grades. Suffice it to say that, even with that design, as we talked earlier with one of the earlier questions, we are still looking to see how we can even improve upon that, to be honest, very pleased with the results from that frac design. What I really like about those wells and we are looking at the other day is just how well they are holding in over time from a decline perspective. I mean, they are very attractive wells for us. But again, it doesn’t mean that, that’s where we are going to stay – standstill with that design, we are going to keep asking ourselves, how can we make it even better as we go forward?

Drew Venker

And John, how do the returns compete with the rest of the portfolio assuming that this uplift is repeatable?

John Lambuth

Well, I can simply tell you we look at our programs, we look at different flat prices like the one Tom mentioned. And certainly right now, the two-mile Upper Wolfcamp and Culberson in that area is one of our top tier programs right now, especially with the most recent well results. So, it looks very, very good to us. And we are very anxious to get that spacing pilot in, so we can start to hone in on exactly what the full potential is for that zone for us from a development standpoint.

Drew Venker

Great. Thanks, everyone.

Operator

The next question will come from Matt Portillo of TPH. Please go ahead.

Matt Portillo

Good morning, everyone.

Tom Jorden

Hi, Matt.

Mark Burford

Good morning, Matt.

Matt Portillo

Just a couple of quick clarification questions, on the theoretical 2017 production with the timing of the Cana completions, I just wanted to see you clarify when thinking about the exit rate Q4 ‘15 of about $985 million a day, would the thought be that with the Cana completions, the total corporate production could reach that level again by kind of Q2 2017 if everything kind of stays on plan as you guys envision it at the moment?

Joe Albi

Yes, Matt, this is Joe. I will answer that. What we have modeled is kind of the worst case where that production doesn’t start until the first half or first part of ‘17. And in that scenario, we are about up to the same corporate total company levels by Q2 ‘17. And if we speed up things, we might find ourselves in maybe the Q1 time period. So again, it’s all timing. And somebody with their questions alluded to the fact that these are big projects, you have got multiple wells all coming on at once. And you saw what roll forward did for us from Q3 to Q4, significant increase in our Cana production, from 405 – Mid-Continent from $405 million to $461 million a day. So, those are big swings. You can see the difference between the Q4 – if you imply a Q4 exit rate with a typical decline or whatever, you might think we are going to be in the high 800s. And all of a sudden, two quarters later, we are 100 million a day higher than that. So, it’s just the nature of the beast and it’s all about timing.

Matt Portillo

Great, that’s helpful. And then just the second question on 2016 guidance, I was hoping that you potentially could provide a little bit of clarity around the midstream impact and the curtailments, I think you guys alluded to some of those still impacting Q1, but was curious how that’s impacted your full year expectations as well. And any color or timing on when those may ultimately reverse here?

Joe Albi

Yes, this is Joe. I will answer that one as well. The gist of it is we are modeling that is going to transpire here in Q1. We have been able to work some other marketing arrangements in and around the downstream curtailment that we have right now and hope to have those plus the remedy itself of the facility that was impacted with the fire that you are aware of. I will finalize by March, late March. And then of course, we have our Hidalgo plant coming on not too far after that and then there is a number of other processing alternatives that are on the map and pretty close to completion that we feel like mid to late this year, we are going to be in very good shape.

Matt Portillo

Thank you very much.

Operator

Our next question will come from Jason Smith of Bank of America Merrill Lynch. Please go ahead.

Jason Smith

Hey, good morning everyone.

Tom Jorden

Hi, Jason.

Jason Smith

So, Tom, the Meramec vessels, well, I think it was a ways away from your other vessels in the Meramec. And I know you have the down-spacing pilot this year, but any plans to test the flanks of your acreage position there at all in 2016? And also just curious if you have any near-term HBP requirements, I guess, outside of what you consider your de-risked area?

John Lambuth

Yes, this is John. Yes, we will be testing quite a bit of extension acreage throughout the Meramec. Part of that will be to essentially hold our acreage. A part of it also would be delineation. We are still constantly surprised, not just by our results, but as Tom alluded to, a lot of competitor results that are kind of changing the landscape within the map in the Meramec. And it’s given us some encouragement, especially as we look more to the Western side is looking much more attractive to us. Unfortunately for us, we have a pretty nice position over there. In fact, that’s where lot of the new leasing that we have picked up is in more of that area. So yes, throughout the rest of this year will be geographically spreading across that map quite a bit with the wells that we would be drilling and that will just help us further delineate the full potential for this interval.

Tom Jorden

Jason, it’s Tom. Just let me follow-up on that. One of the things that we are seeing in the Meramec is a fair variability, but also a fair availability of results with landing zone. Landing zone seems to have a fairly strong impact in a way that has surprised as compared to the Woodford below it. And so I think as we go forward, you are probably going to hear us talking more and more about the Mississippi as opposed to the Meramec that some of the lower section, you hear the Osage being talked about as the target. And that’s looking more and more interesting to us. There are some really good wells out there that are hard to explain if you only have the Meramec to explain it with. And so as John said, there is a tremendous amount of upside for us not only in our acreage but also operational improvements as we test landing zones and then also completions. We are pretty bullish on that play right now and our position. And although we generally read competition everywhere, there is some competition out there that’s giving us a lot of good information and it’s just shining a very positive light on our position.

Jason Smith

Thanks for that detail. And my follow-up is a little bit different direction here. The dividend is now a lot bigger part of your cash flow at current prices, you obviously have the cash on your balance sheet to cover it, but just curious on your thoughts around where it fits and the benefits of maintaining at current levels?

Tom Jorden

Well, we are committed to dividend. We have got some very long-term owners that for whom it’s important. I will say, I was expecting that call because I know so many of our peers in their end of your late release had addressed their dividend. We have a Board meeting next week and that’s certainly going to been an active topic with the Board and we will make decision around what’s appropriate.

Jason Smith

Thanks Tom. I appreciate that.

Operator

Our next question will come from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

Michael Hall

Thanks. Good morning.

Tom Jorden

Hi, Michael.

Michael Hall

I was wondering if you could maybe just provide a little additional granularity around the planned completions in the 2016 program outside of these kind of key projects that you have highlighted. First in the Permian, outside of the Tim Tam and the Reeves County infill, I guess you talked about 31 completions coming out through the course of the year. I am just curious what the composition of those other wells looks like, be it Bone Spring or Culberson, Upper Wolfcamp, Lower Wolfcamp, etcetera? And then I have...

Joe Albi

Yes, this is Joe. As far as the net well counts of wells that are being completed during the year, we see about the majority of them, two-thirds of them are in the Wolfcamp, Culberson and Reeves. And then the remainder is primarily Bone Spring. And as I have mentioned in my discussion early on, we got a couple of rigs hitting them right now, right. And we are going to drop them down. So you are going to see our net completions in the area overall, wells waiting on completion increased to about 20 or something in the middle of the year. And then it’s going to come on down as we pull those rigs back and keep our frac crude running at taper itself down to just six waiting on completion at the end of the year. So sorry, two-thirds Wolfcamp, one-third Bone Spring and really just kind of she goes consistent completion pattern during the year.

Tom Jorden

Yes. No, he is absolutely right. I will just point out the Bone Spring component, essentially those wells were drilled and so they will be completed in the first half. And then all of the rigs for the rest of the year will be dedicated towards Wolfcamp, towards finishing up the pilots. And then the rest of the time, it’s all about acreage holding. So yes, there is a component of Bone Spring, but that’s early in the year and everything else to the rest of the year is Wolfcamp.

Michael Hall

And that Wolfcamp activity outside of the Tim Tam and the Reeves and so, is that predominantly upper or lower or that’s from a leasehold perspectives are you incentivized to...?

Tom Jorden

As we have talked about before, it all kind of depends on the lease and what we need to do in order to hold, depend on the lease term, a lot of them maybe lower Wolfcamp’s, others could be upper. I don’t have that breakdown for you. I do know that as a program, we are about half and half, half net wells in Culberson, half approximately in Reeves for the year.

Michael Hall

Yes, that’s helpful. And then I guess, similar question in the Meramec program, I am just curious how many – I am sorry if I missed this, but how many completions are you expecting in 2016 in Meramec?

Joe Albi

Yes, this is Joe. The majority of them, about two-thirds will be – this is not counting the infill program, which we said we have deferred into the Woodford development program, which were deferred in ‘17, but of the ‘16 completions, approximately two-thirds are in the Meramec and then just some little singles in and around that. But John, I don’t know if you want to move to that?

John Lambuth

No. Joe is absolutely right. Again, we are pushing back in the Eastern core development theoretically into ‘17. The majority of our completions will be Meramec. And then we have the occasional Woodford one-off well where we still continue to expand and test the boundaries of our Woodford play.

Michael Hall

And how many completions is that, sorry if I missed it?

Joe Albi

It will be total of about 16 net completions.

Michael Hall

Great. Thanks. Then I just wanted to understand a little better around the decision to – I guess yes just the decisions around the timing of that road development and bringing that on production late in the year, early next year, is that – it sounded like it’s more a function maybe of holding acreage and in the Mid-Continent as opposed to just logistical considerations with….?

John Lambuth

Well, this is John. And I will just say, as I alluded to in my comments, we have a partner and we develop these roads. We coordinate with our partner from a standpoint of the frac calendar. We recognize that to achieve the optimal result, we have to work together. We have to time our frac schedule appropriately as we bring these wells on. Our partner has indicated to us that, at this time they would like to delay that frac schedule. And so we are working with them and coordinating with them to the best of our ability. We have emphasized we would like to move it up some, if we could. We decide the positions were taken, but I think we would like to move it up in the year if we could. And we are having those ongoing discussions right now. And we will see where it ends. I think what we have done is we presented you maybe you could call the worse case scenario where they get pushed all the way to early ‘17. But there is a chance perhaps we can push them up earlier into ’16, I think that would be our preference.

Michael Hall

That’s really helpful color. I appreciate it, John. And then last one or I guess two more quick ones for me. Number one, just to be clear, I want to make sure I am reading this right, the total CapEx is at $650 million to $700 million or is that $50 million of midstream included in that $600 million to $650 million?

Mark Burford

No, Mike. The $600 million to $650 million is the E&D spending. There is an incremental $58 million from midstream and other capital incremental to the $600 million and $650 million, so the $650 million to $700 million with it.

Michael Hall

Perfect. And then last one, you mentioned you had some minimum volume commitment payments, is there much more exposure to that through the course of ‘16 anyway to quantify that?

Joe Albi

Yes. This is Joe. As best as we are modeling right now, we have taken the gist of that.

Michael Hall

Alright. Thank you very much.

Tom Jorden

Thank you.

Operator

Ladies and gentlemen, this will conclude our question-and-answer session. I would like to turn the conference back over to Karen Acierno for any closing remarks.

Karen Acierno

Well, thanks everyone for joining us. Apologies to those of you who are still in the queue, we have run out of time, but if you would like to call up with those questions, feel free to do so. And have a great day.

Operator

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.

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