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Edited Transcript of XEC earnings conference call or presentation 5-Nov-19 4:00pm GMT

Q3 2019 Cimarex Energy Co Earnings Call

DENVER Nov 13, 2019 (Thomson StreetEvents) -- Edited Transcript of Cimarex Energy Co earnings conference call or presentation Tuesday, November 5, 2019 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* G. Mark Burford

Cimarex Energy Co. - Senior VP & CFO

* John A. Lambuth

Cimarex Energy Co. - SVP of Exploration

* Joseph R. Albi

Cimarex Energy Co. - Executive VP, COO & Director

* Karen Acierno

Cimarex Energy Co. - VP of IR

* Thomas E. Jorden

Cimarex Energy Co. - Chairman, CEO & President

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Conference Call Participants

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* Andrew Elliot Venker

Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil & Gas Exploration & Production

* Arun Jayaram

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Brian Kevin Downey

Citigroup Inc, Research Division - Director

* Gabriel J. Daoud

Cowen and Company, LLC, Research Division - Senior Analyst

* Jeffrey Leon Campbell

Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services

* Michael Stephen Scialla

Stifel, Nicolaus & Company, Incorporated, Research Division - MD

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Nitin Kumar

Wells Fargo Securities, LLC, Research Division - Senior Analyst

* Noel Augustus Parks

Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s

* Wei Jiang

Crédit Suisse AG, Research Division - Research Analyst

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Presentation

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Operator [1]

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Good morning, and welcome to the Cimarex Energy Company Third Quarter 2019 Earnings Release Conference Call. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Karen Acierno, Vice President of Investor Relations. Please go ahead.

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Karen Acierno, Cimarex Energy Co. - VP of IR [2]

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Thanks, Gary, and good morning, everyone. Welcome to our third quarter 2019 conference call. An updated presentation was posted to our website yesterday afternoon, and we may reference that presentation on our call today. Just as a reminder, our discussion will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements on our news release and in our 10-Q, which will be filed later today.

Also available is our latest 10-K for the year ended December 31, 2018. All those will have the risk factors associated with our business. We will begin our prepared remarks with an overview from our CEO, Tom Jorden; then Joe Albi, our COO, will update you on operations, including production and well costs. EVP of Exploration, John Lambuth, and Cimarex's CFO, Mark Burford, are here to help answer any questions. As always, and so that we can accommodate more of your questions during the hour we have allotted for the call, we'd like to ask that you limit yourself to one question and one follow-up. Feel free to get back in the queue, if you like.

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

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [3]

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Thank you, Karen, and thank you all for joining us on the call this morning. I will briefly discuss our operational highlights and focus, followed by our COO, Joe Albi, who will provide a more detailed breakdown on our quarterly details. Cimarex had a solid third quarter in a challenging macro environment. Our oil production came in above the midpoint of our guidance range. Total oil grew 8% sequentially, with Permian oil growing 6% sequentially. Permian oil growth is projected to continue. While we plan on continuous sequential growth, occasionally we find that projects are ready to come online sooner than planned. In all cases, we bring our wells online as soon as they're ready. We lowered our capital guidance full year by $50 million at the midpoint, while keeping our production guidance and well count unchanged. Commodity prices continue to be a challenging headwind, particularly for natural gas and natural gas liquid. In spite of these headwinds, we expect to exit the year without incremental borrowings. Furthermore, we are pleased to be returning cash to shareholders in the form of our dividend, which we intend to continue to grow over time. We continue to deliver excellent fully burdened returns. As we have described in the past, we measure ourselves on a fully burdened basis, which includes all drilling, completion, facilities, midstream, land, science and G&A.

Our well productivity and cost improvements for the past few years have resulted in robust and repeatable investment return. Our current returns are also more resilient to drops in commodity prices than they were 5 or 6 years ago. As an example, we have stress tested our total program returns for each of the 3 prior years 2016, '17 and '18 by modeling all future cash flows as if the flat SEC prices in effect at the end of Q3 lasted forever. Even with these low prices on a go-forward basis, our total program returns are robust. Our investment performance has become repeatable, robust and better defendable against commodity price swings. With this knowledge and confidence, we are doing a better job of planning our future. We also continue to benefit from the tremendous work and science that we have put into understanding resource play development. Our program is almost entirely development at this point. We still have a surprise or 2, but we continue to gain operational confidence in our development and spacing decisions. We also continue to make a mistake or 2 along the way. This is the nature of progress.

We are laser-focused on all elements of our cost structure, capital expenditures and lease operating expenses. As we look into 2020, our plan is to generate free cash in a $50 WTI oil, $2.50 NYMEX Gas environment. We will remain disciplined, cautious and flexible. We are not burdened by service contracts or undue lease expiration issues and can grow our business at the right pace for the current environment.

Now I'll turn it over to Joe to discuss our operations in more detail.

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Joseph R. Albi, Cimarex Energy Co. - Executive VP, COO & Director [4]

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Thank you, Tom, and thank you all for joining our call today. I'll touch on the usual items, our third quarter production, our fourth quarter and full year production guidance, and then I'll finish up with a few comments on LOE and service cost. As far as Q3 production volumes go with continued strong execution, we achieved another nice jump in our production during Q3. Our third quarter posting for net equivalent production came in at a company record 287,000 BOEs per day, 3% above the top end of our guidance range of 265,000 to 279,000 and up 4% and 31% over Q2 '19 and Q3 '18, respectively.

The guidance beat was driven by continued strong Permian production growth and higher-than-forecasted NGL recoveries during the quarter. On the oil side, we posted another company record for production. Our Q3 oil volume came in at 89,700 barrels of oil per day, beating the midpoint of our guidance by 1,700 barrels a day and putting us up 8% and 40% over Q2 '19 and Q3 '18, respective postings. Although we saw quarter-to-quarter oil production increases in both the Permian and the Mid-Continent, the Permian drove the increase with our Q3 Permian oil volume of 74,800 barrels a day, up 6% over Q2 '19 and 53% over Q3 '18.

With the posting, the Permian now accounts for 83% of our total company oil production. Shifting gears to capital and our full year production guidance. As Tom mentioned, through efficiency gains and cost savings, we've lowered our full year 2019 E&D capital guidance to $1.3 billion to $1.4 billion, it's down $50 million or 4% at the midpoint of our previously issued guidance.

That said, we've kept our forecasted full year net completion count at 80 net wells. With our revised completion scheduling, our updated model projects our Q4 net equivalent volume to range from 272,000 to 292,000 BOEs per day, with the midpoint down just slightly from Q3, due primarily to uncertainties we have surrounding the extent of any ethane rejection that may occur during Q4. On the oil side, we're modeling a range of 86,000 to 92,000 barrels a day, with a midpoint virtually flat to Q3, and that's a byproduct of our projected 11.2 net wells coming online during Q4, comparing to the 21.4 that we had online in Q3 and 39.5 in Q2. So with our strong execution over the past 3 quarters, we're increasing our full year guidance ranges for both equivalent and oil production. We've bumped our full year net equivalent production guidance to 273,000 to 278,000 BOEs per day. That's up 3% at the midpoint from our guidance last call and with a range of 84,500 to 86,500 barrels of oil per day. For full year net oil production, we've raised the midpoint of our guidance -- our oil guidance by 500 barrels a day or approximately 1% from the range that we quoted last call.

Jumping to OpEx. We had a strong quarter for our lifting costs. Our Q3 posting of $3.34 per equivalent barrel was down 5% from Q2 and put our year-to-date lifting costs of $3.39 per BOE, just slightly above the low end of our full year guidance range that we quoted last call of $3.30 to $3.65 and represented a drop of 6% from our 2018 average of $3.62 per BOE.

With the posting, we've tightened our full year lifting cost guidance to a range of $3.30 to $3.55 per BOE, lowering our midpoint by $0.05 per BOE from the range that we've quoted last call.

And lastly, some comments on drilling and completion cost. With the slowdown in industry activity, we're seeing cost reductions on both the drilling and completion sides. Current drilling day rates are down 5% to 9% from last call, and with service cost reductions and our continued focus on frac design, we've dropped our completion AFEs by 11% to 12% from last call, which translates to a 17% to 19% drop from completion AFEs earlier in this year. As such, we've realized sizable drops in our projected total well costs during the quarter. In our Wolfcamp program, as an example, cost reductions have dropped our generic Reeves County 2-mile Wolfcamp A AFE to $9.3 million to $11.8 million, again, depending on facility design and frac logistics. That range is down $700,000 from our estimate last call, $1.1 million from earlier this year and down $1.6 million from our estimate late last year.

Our shallower Wolfcamp A wells in Culberson County are running about $500,000 less than this range, with an AFE range of $8.8 million to $11.1 million. Efficiency gains that we derive through our multi-well development drilling projects, as we've talked about before, put our average development well -- total well costs at the low end of these ranges. And in the Mid-Continent, our refined completion design, improved operating efficiencies and service cost reductions, combined have reduced our AFEs in both our Woodford and our Meramec programs. For example, our current 2-mile Meramec AFE is running $8.5 million to $10 million. That's down $1 million from last call, $1.5 million from earlier this year and $3 million from the costs that we quoted in early 2008 (sic) [2018].

So as Tom mentioned, we've made tremendous strides in our cost structure, particularly on the total well cost side, and it really is showing up in our statistics. Through operational efficiencies, realized cost reductions and by drilling longer laterals, our 2019 Permian program total well cost per lateral foot metric is estimated at $1,150 to $1,200. Now this estimate includes all necessary costs to bring a well online, drilling, stimulation, facility and flow-back cost and it implies a 20% reduction over that same metric that we saw in 2018.

So in closing, we had a great Q3. We executed on the strong production ramp we promised and forecasted, with equivalent in oil production guidance speeds along the way. We've raised the midpoint of both our full year net oil and equivalent production ranges, with resulting year-over-year growth of 26% and 24% for net oil and net equivalent volumes, respectively. Our cost structure is strong. Our Q3 lifting cost was down 5% from Q2, and we've lowered the midpoint of our full year guidance by $0.05 per BOE. We've lowered our total well costs significantly, with our average Permian total well cost metric in the $1,150 to $1,200 per lateral foot range, down 20% from 2018 levels. We're executing on all cylinders and we're well-positioned to deliver on the capital, the activity and the production plan that we put in place at the beginning of the year.

So with that, I'll open it up for Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Gabe Daoud with Cowen.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [2]

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I appreciate all the prepared remarks and the high-level framework on '20. I was, I guess, wondering if you could just give us a sense on assumed Permian activity levels for the range of oil prices that you gave, whether that's in terms of rigs, crews or turn-in-lines? And then, I guess, what kind of overall growth do you see for corporate oil production next year?

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G. Mark Burford, Cimarex Energy Co. - Senior VP & CFO [3]

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Yes, Gabe. This is Mark. Yes, for 2020, we're still working on our plans, and we don't have a lot -- want to give a lot of detail on the plan into 2020. The current 8 rigs in the Permian, we have some plans that we'd actually increase some of that rig count into 2020 in our current forecasting, the scenarios we're running. And then the turn-in-lines, with the cycle time we're seeing, our turn-in-lines have improved with the compressed cycle times. So the different scenarios we're working on in 2020, we are seeing activity, a good paced activity into 2020. And we're focused on that Permian oil growth, and we're forecasting growth into 2020.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [4]

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Understood. And I guess just as a follow-up, I think this year, you had some exploration spend in the budget. And just, I guess, as a way to maximize free cash flow next year, do you think that comes out of the budget? And then, I guess, if you could maybe even just quantify that number of exploration spend that was in the budget for this year?

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John A. Lambuth, Cimarex Energy Co. - SVP of Exploration [5]

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Yes, this is John Lambuth. We did have some exploration spend. But again, it's not that much money in regard to 2019. When we do have a land effort, usually, we're very early entrant, thus, our entry costs are extremely low. So you really don't even see it within the overall, call it, capital framework. So it's not something that I think one needs to worry too much about in terms of our capital plans for the following year.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [6]

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We track that very closely as a percentage of our total capital, that's a metric, with our focus on fully burdened returns, that we've watched from the inception of Cimarex. We haven't budgeted tremendous amount for exploration. I'm hoping that we're going to find some things that we love and we should have plenty of room there.

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Operator [7]

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The next question is from Arun Jayaram with JPMorgan.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [8]

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Tom, I was wondering if you could comment your thoughts around risk associated with your federal acreage position as we approach an election year? And have you had any conversations with the Governor of New Mexico? And just general thoughts around that risk, which has been evident since some tweaks in early September?

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Operator [9]

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It appears that we may have lost connection with the main speaker line. I am going to put the call on hold and try and reconnect.

(technical difficulty)

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [10]

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Tom, can you hear me?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [11]

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I can. Thank you.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [12]

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Okay. Did you hear my question on federal acreage? If not, I can restate it.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [13]

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Yes. No, we did not. We lost your connections, but can you please restate?

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [14]

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Okay. Great. Tom, I wanted to get your thoughts on potential risk around Cimarex's state of federal -- pardon me, your federal acreage position in the Permian as we approach the election year. Have you had any conversations with the Governor or officials in New Mexico? And how do you think about that risk on a go-forward basis?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [15]

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Well, a lot of questions there, Arun. But certainly, Cimarex has been engaged with the Governor and such. I have not personally discussed this issue with the Governor. Here's how I think about the risk, we're in a primary season, and as always, in the primary season, some ideas get floated that are a bit extreme. I mean, if you go back 4 years and watch either the democratic or the Republican debates, I think you'll make that observation. We are certainly exposed to New Mexico. I mean we've been very forthcoming on that. We don't think that there is going to be a ban on fracking on federal lands. We are nicely positioned for Texas as well. So even if it were to happen or there to be some discussion around that, we've got plenty of places to adjust and move to. But I'll just close by saying, federal royalties are such a huge part of the state of New Mexico's total revenue stream that I cannot imagine a situation where the federal government would close that door on New Mexico. But we will be prepared either way with flexibility in our program.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [16]

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Great. And just my follow-up. Tom, going back to Gabe's question, Slide 19. You've highlighted different free cash flow yields in a 2020 program from 50 to 60. I was wondering, is -- at the lower end of that band, would you still anticipate growing some oil next year? Or would that resemble more of a maintenance program based on the initial forecast?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [17]

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No, we grow oil under all those scenarios.

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Operator [18]

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The next question is from Neal Dingmann with SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [19]

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First question I had was just pertaining to -- could you talk about a little bit just on your Delaware plans by county? It looks like most continue to be for '19 in Culberson. I'm just wondering, and I fully understand you don't have the detailed 2020 out yet, maybe just talk a little bit about if the area of focus would be relatively similar?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [20]

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Well, I would say it will be relatively similar. We're always going to have a very healthy level of activity in Culberson with our joint development agreement with Chevron. We have a lot of projects we like in Eddy County, a lot of projects in Lea County, but Reeves County also has a lot of activity. We're getting after that Resolute acreage in addition to the acreage we brought to the table. And we're going to be active really across our portfolio.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [21]

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Okay. And then one just follow-up. Just looks like for '19 you had about $70 million budgeted for midstream. Again, knowing full well you don't have detailed 2020, just on average, do you think the spend for, I would just say, non-D&C will continue to be about the same? Or will that start to trickle down a bit?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [22]

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Well, this year, anticipated to be $70 million or maybe slightly below. And then as we move into 2020, our focus is going to be on trying to capitalize on the infrastructure that we have and minimize any midstream associated costs that would be tied to our development programs.

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Operator [23]

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The next question is from Mike Scialla with Stifel.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [24]

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Congrats on the quarter. Tom, you said that, that $50 a case with the 2% free cash flow yield that you still grow oil. I just want to see if you could provide a maintenance capital level that you need to spend to keep your oil flat [to stay] with the projected fourth quarter rate?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [25]

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Yes. I'm going to bounce pass that to Mark. We -- I don't know if we've calculated that.

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G. Mark Burford, Cimarex Energy Co. - Senior VP & CFO [26]

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Yes. Yes, Mike, we haven't calculated that pressure. We're working on 2020 plan right now, which does anticipate growth in our oil. And we're working on allocation, we're allocating into '20 as I'm currently looking at it, even a greater portion of our capital going to the Permian, but we don't have -- I don't have a maintenance capital associated with that. But that yield that we're talking slightly under 2% to nearly 10%, is a scenario that -- some of the scenarios we're working on with a steady to slightly down D&C capital that derives that type of yield. And it's basically kind of anticipating budgeting in that $50 and $2.50 type NYMEX oil and gas price with -- and again, that's steady to slightly down capital, holding that flat and running that through the year.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [27]

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No problem. Okay. And then the $2.50 gas price, I guess, we're just looking at Waha prices still below $1 even with the Gulf Coast Express online. I assume that what you'd mentioned earlier in your prepared remarks something that you're using with kind of the current prices held flat. How does that I guess impact your thinking about your plans for 2020? Or does it?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [28]

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Well, we -- those NYMEX prices are always -- we quote that because that's the index marker. But we bring that back to our actual receipt price at the wellhead. So we're accounting for all of those basis differentials fully in our go-forward plans. Mark, do you want to touch on that?

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G. Mark Burford, Cimarex Energy Co. - Senior VP & CFO [29]

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Yes, that's right, Mike. So Mike, we run different flat cases or even price -- the current forward strip for 2020 is right around $2.50, I think it was $2.52 last Friday. So it's fairly close to the flat price -- NYMEX price we're using, but to the extent we adjust from a -- to a flat case from the strip case, we keep a portion of it to reduce the realized prices in areas where the local market differential's based on the forward curve of those differentials. So we bake -- fully bake in all those differentials.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [30]

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So our cash flow fully incorporates the local pricing for all products business.

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G. Mark Burford, Cimarex Energy Co. - Senior VP & CFO [31]

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Yes, for gas and NGL. That's right.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [32]

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Yes.

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Operator [33]

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The next question is from Jeffrey Campbell with Tuohy Brothers.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [34]

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And congratulations on the quarter. Slide 8 illustrated that the second quarter '19 contained half of the entire 2019 time lines and then activity trailed off in the second half. Since 2020 becomes a year of potentially meaningful free cash generation, I was wondering if you're going to follow a similar operational plan as you did in 2019. Or would you prefer to make the free cash generation more level loaded throughout the year?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [35]

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Well, I'll start this off and then let Mark comment. We -- ideally, we would love if it were level loaded across the platform. But with 8 rigs running and these development projects, there is a certain structure to when we bring these wells online. And this is just our business. We are making a good attempt to try to smooth out these field operations to try to have a more even-field cadence. But I want to just be clear, our primary goal is to generate outstanding returns on invested capital, stress test those returns for the downside and make sure that we account -- we account for every single cost incurred in bringing that production online. The production timing is a consequence of good decisions and not a primary driver. Yes, we'd love for this to be smooth and even, but the world doesn't always behave that way with these development projects. Mark, do you want to touch on that?

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G. Mark Burford, Cimarex Energy Co. - Senior VP & CFO [36]

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Yes, and absolutely, Tom, it is exactly what you're saying and the fact that the number of wells brought on into a production in any particular quarter can be varied by the size of the pads we're drilling in a different development. The pace of development that we're drilling for wells I don't see completed per quarter is much more consistent. And our operational cadence is what we're focused on is operational cadence of our activities in drilling -- or completing our laterals and drilling our wells. And then the timing of these well productivity that we brought on during any quarter will be varied depending on, again, the size of the pads, the areas that we're drilling and even can vary somewhat with the working interest that we have in the areas we're bringing on, since this is a net well completion per quarter. We are definitely focused on our operational cadence, our well lateral feet drilled per quarter and again the quarterly production cadence of wells brought on line can be more -- look more erratic than what the underlying operations represent.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [37]

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Yes. And I want to make one other comment, we're focused on costs, I said in my opening remarks, that, that is a laser focus of ours. And to smooth out that could be done but it could involve significant costs. A mobilization cost, getting enough water on pad as you need it. And so there are a lot of other considerations, but we are going to sound like a broken record here, we are driven by returns on invested capital. Joe, you want to comment on that?

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Joseph R. Albi, Cimarex Energy Co. - Executive VP, COO & Director [38]

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Yes, I do. I wanted to use this year as an example of this completion cadence that both Mark and Tom are talking about. If you look back over the year, and I'm going to talk about multi-well projects in the Permian. In Q2, we had 2 multi-well projects on a gross basis and there only were 2 wells per project, and that was 4 net wells for the -- 4 total gross wells for the quarter. In Q2, we had 6 multi-well projects. It ranged anywhere from 2 to 7 wells per project and on the average, there were 5 wells for every one of those projects. So in Q2, these 6 projects brought on 30 wells. In Q3, 5 projects brought on 21 wells. And as we go into Q4, 2 of these projects are bringing on 12 wells. And as I mentioned in my opening statements, that's really the byproduct of our flat oil production here in Q4. So we're always going to have some semblance of that completion cadence in our production growth.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [39]

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Well, now I really appreciate the color. And I think your points are fair and then probably what we should end up doing is thinking of free cash on an annualized basis rather than getting too hung up on sequential. But I thought it was a fair question to ask.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [40]

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It is a totally fair question. And we look at this -- I was on the call early this morning on just this topic. And I was convinced that by spreading it out further, we get better returns and lower cost structure. So it's a really fair question. We welcome the question. But some of this is just details that in ironing a program out, sometimes the chips fall in a nonideal way. I'll just leave it there.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [41]

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Okay. As my follow-up, on Slide 28, it references Cimarex's 2 gas gathering systems, and Slide 29 illustrates the water management system. I was just wondering, is the longer-term view to keep these assets in-house for cost control since you guys mentioned you're very focused on costs? Or could you sell them and still have an advantaged cost structure?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [42]

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Well, that's a very pertinent question to us because as we've discussed in prior calls, this is something that is an active subject to investigation. We've done a lot of work over the last quarter on this. We certainly have a very valuable gas gathering system and a very valuable water gathering system. I will tell you that we have and continue to explore monetization options, but it really is a trade-off between a quick hit of cash when you monetize versus the longer-term increased operating expenses. If I were surprised by anything, even at today's multiples, it's not an obvious decision. You can sell them, take the cash now, which you're going to pay for it in perpetuity with higher operating costs. We think we've got one of the lowest cost structures around. We realize that, that cost structure is a real asset of ours. The gathering system, both for gas and water provides us tremendous operational flexibility. So although we continue to explore that, we have conversations on this every day, I will say that for now, we have not made a commitment to monetize these assets. It's an active argument at Cimarex, it's a healthy argument, but it's pay me now or pay me later type choice.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [43]

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Okay. Great. Now I appreciate that color. And again, congratulations on the quarter.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [44]

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Thank you.

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Operator [45]

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The next question is from Noel Parks with Coker & Palmer.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [46]

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I just had a couple of questions. Thinking about Culberson County and the economics out there. I'm also thinking about gas and NGL issues that the whole industry has had. How sensitive do you consider the Culberson County economics to sort of -- the uncertainty around the takeaway and processing part of the equation, just sort of thinking there's that piece and then, of course, there's the demand piece for the product that also it fluctuates a lot with NGL?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [47]

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Well, we don't see an uncertainty in takeaway of processing. We've got that system with multiple outlets for takeaway, we have multiple outlets for processing. And I'll let Joe comment on this, but our operations and marketing group have done a tremendous job when we've had occasional interruptions with our processors or gatherers, transporters. We've been able to very adeptly redirect that flow because we do control that asset from a gathering standpoint, and we have multiple outlets. Oil is the dominant phase, dominant revenue phase in Culberson County. I wish gas and NGLs were a stronger revenue component but even at current pricing, with this hostile price environment, the economics of Culberson County are supremely attractive to us. And we just see upside to pricing if we can make the kind of returns we're making now, it's just only going to get better if we see any kind of recovery in gas and NGL pricing. I mean those economics -- I appreciate your question because I think the economics of Culberson County are underappreciated. Not only is Culberson County, as we demonstrated in our slide, one of the premier counties for cumulative oil production, but we deliver that oil at a basin-wide low operating cost because of the nature of that reservoir and the low operating cost of our system. So we're pretty pleased with that asset. Joe, you want to comment on that?

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Joseph R. Albi, Cimarex Energy Co. - Executive VP, COO & Director [48]

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As far as takeaway goes, Tom's hit it right on the head as far as the value to the infrastructure kind of leads into the prior question. Triple Crown, as an example, we have a large system for gas gathering, which can offload to 4 or 5 different processors at any point in time. We see adequate processing capacity in the Delaware to handle not only our gas but the majority of the basin's gas in the near term. As far as NGL takeaway is concerned, we're linking our sales to those owners of the production facilities who have pipe out of the basin. On the oil side, we're doing the same thing. 85% of our oil is on pipe, and we're signed to purchasers who can get us out of the basin. And on the gas side, as we've talked about, the residue gas side, we've secured sales of gas. Our gas through 2020, 100% through the first quarter, is committed to be sold. And we got 75% on the average over the remainder of 2020 that's committed to purchasers all the while we've secured takeaway on whitewater to get to Waha and also, I think, in our earnings presentation, you'll see that we've committed to Whistler. So we're long-term thinking, and it's all about getting that basin out -- or getting that product out of the basin.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [49]

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Great. And my other question, I was just curious, have you seen any significant change in the leasing environment in the Woodford, Meramec over the past few months or so?

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John A. Lambuth, Cimarex Energy Co. - SVP of Exploration [50]

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This is John. Well, certainly, there's a lot less activity within the whole stack play. And then yes, I think it's fair to say not as much in terms of competition, if one's looking for that incremental acreage. So yes, things have slowed down definitely in that basin current day.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [51]

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One change I've observed is because so many of our competitors are cast with living within their cash flow. There are a lot of operators that are looking to sell non-operated interest. A number of operators because they're sticking to that discipline of living within their cash flow, find that they only have the cash flow to participate in their own operated properties. So we've had some pretty good opportunities in the Anadarko and in the Delaware Basin to pick up additional interest in some of our projects at costs that, quite frankly, we haven't seen in years.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [52]

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Terrific. And just to clarify, are those things that -- are people actively approaching you? Or you're just aware as you see people going on consent that there might be an issue?

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John A. Lambuth, Cimarex Energy Co. - SVP of Exploration [53]

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It runs the gamut. Mainly, it's just they make it aware that they are looking to get out of the wells if we're operating and in some instances then we make an offer. Sometimes it is at poolings, where we get it through the pooling. It varies. But as Tom alluded to, there is quite a few operators who, to stay within that budget, they are getting out on a non-op perspective. So we've done very well in picking up some of that additional interest.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [54]

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As an interesting aside and the statement of how free markets function, private equity has come out of the woodwork on this subject. Private equity is highly attuned to this opportunity and the number of private equity players are actively soliciting relationships, where they will pick up this non-operated interest if operators don't want to participate. So there's a little market that's developing for this. But it's a change in our business. We wouldn't have seen this a few years ago.

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Operator [55]

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The next question is from Drew Venker with Morgan Stanley.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil & Gas Exploration & Production [56]

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Tom, you've talked a lot about maximizing NPV and rate of return and clearly, as you talked about 2020, free cash flow is another important aspect. Can you talk about how spacing might play into your optimization of returns versus NPV in the current commodity price backdrop, as you said, it's kind of harsh at this point? I think especially given that you have probably as good of an understanding of spacing and downhole well geometry as anybody.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [57]

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Well, I appreciate that question, Drew. We've talked about this at length, and we love talking about it because we live it every day. We see the spacing decision as a trade-off and the natural interplay between rate of return and net present value. And we have these discussions every day. In fact, I had a discussion this morning on a spacing project, where we made it clear to one another and to our operating group that we will not spend money to bring on noneconomic production, at least, I'll say we won't do it on purpose. And so studying these projects and understanding where your breakover point is and when you should stop down spacing is really an important element. So we seek to not be wasteful by having our wells too coarsely spaced, and we seek to not be wasteful by having our wells too tightly spaced and there are waste on both sides of that. It's not a one size fits all. It changes from area to area, it changes from reservoir to reservoir. And I'll just say, I have tremendous confidence in our team, in our approach and understanding the science behind this, that's -- John leads that effort. And as I said in my opening remarks, we make mistakes, we're not perfect on this subject. And yet I really am confident in saying that we are continuously getting better. You want to comment on this, John?

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John A. Lambuth, Cimarex Energy Co. - SVP of Exploration [58]

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Well, just as a follow-up, I would emphasize what Tom said, not one size fits all. We definitely see variations in our spacing thoughts, even within the Wolfcamp as we go across our acreage from Culberson to Reeves to Lea. And then there are so many dynamics in there, but we have a very good understanding of it and that we're able to adjust on a section-level basis to come up with the proper spacing. So I feel very good about what we'll be able to do in '20 in terms of the development projects we currently have planned and the appropriate spacing for it.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil & Gas Exploration & Production [59]

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I was just thinking, just as a follow-up to that. If you're using 2019 as a starting point and point of comparison. If you're -- we end up being at the lower end of this $50 to $60 price range you laid out for 2020. Does that generally bias you towards wider spacing? And then conversely if we're at $60 tighter spacing?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [60]

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We've run those models, and we've looked at not only commodity pricing but also net revenue interest. And I will say that our experience is that the boundary on overspacing can be so punitive that it's not really going to change within the price file that you just quoted. That I would not see us at a $60 or even $70 oil price making different spacing decisions.

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Operator [61]

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The next question is from Betty Jiang with Crédit Suisse.

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [62]

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I have 2 questions on cost. First, on CapEx. There has just been tremendous progress this year, cutting the Permian well costs by 20% year-on-year. Just wanted to understand, are there additional levers to move that $1,150 to $1,200 per foot cost even lower as we look out to 2020? And are there any of that being reflected in the preliminary free cash flow outlook?

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Joseph R. Albi, Cimarex Energy Co. - Executive VP, COO & Director [63]

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Betty, this is Joe. We're constantly looking at how we can become more and more efficient. A lot of the recent drop that we've seen has come as a result of service cost reductions on the completion side. We're pushing hard to optimize efficiencies and combine some of our midstream efforts and contractors into laying the flow lines for our wells to the midstream systems. As an example, we're looking at our battery design so that we could produce more wells into a battery and potentially apply a drill-to-fill type of strategy to optimize our completion costs. So it's hard for me to give you, "hey, we can reduce it by x." But I will tell you that it is a strong emphasis around this company right now that costs are relevant in this price environment and in order for us to really be a top performer. So it's our focus.

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G. Mark Burford, Cimarex Energy Co. - Senior VP & CFO [64]

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Yes. Betty, and as far as it being forecasted into '20, our typical practice is to kind of use the current AFE that we have in hand, kind of our current cost structure and not to make assumptions on better -- further improvements from there, even though there's potential for that.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [65]

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And let me join the course here. We want to fairly and transparently report our costs. We think the focus on cost per lateral foot is a good focus. That said, Cimarex operates over a fairly wide geographic range within the basin, and our costs will vary significantly across the basin. We have some development projects in Culberson County that all in are below $1,000 a foot, and we're averaging that with some projects in the deep basin, where you have a little more pressure and a little more drilling and completion challenges that average that number up. We also have some 1-mile wells in our portfolio, although on average, we're certainly going to longer and longer laterals as shown in our deck. But I don't want to discourage our teams from bringing forward 1-mile projects that have outstanding returns. And so we're going to continue to report a transparent average, but within that average, there's a lot of structure.

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [66]

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Got it. No, that's really helpful color. And then similarly, on the other cost item, LOEs. I mean, historically, [all your] production growth typically put upward pressure on cost, but that has not been the case for you guys this year. Going forward, how should we expect LOE to evolve as your growing oil production in the Permian by seeing declining gas production out of Mid-Con. So do you think there is a bit more room on LOE to come down on a per-unit basis?

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Joseph R. Albi, Cimarex Energy Co. - Executive VP, COO & Director [67]

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This is Joe again. I -- this quarter, we saw a nice reduction in our overall absolute LOE, even with the Resolute assets coming on board, tailing in Q1. We were down on the LOE side, but our workover expense was up and that's a result of converting to lift. So there's a lot of wells to lift. So there's a lot of variables in that number because we've got the day-to-day LOE cost to operate the wells and then you've got the workover expenses that slide into that category as well. Our focus is going to remain on the same items we are now. The bigger emphasis is going to be on SWD or Salt Water Disposal, that's where the majority of our cost reductions have been achieved, and as we're going forward, they're going to -- we're going to be able to take advantage of them. That's where that infrastructure that keeps popping its head up comes into play. The optionality and the cost optimization of those systems provide us, allow us to swing water to use for our fracs. And at the same time, we're using that water for our fracs, we're not having to incur any kind of electrical charges to the SWD wells to dispose it. Although that sounds like a small item that can add up. So that's where those efficiencies have been coming from, and that's where our focus is going to be going forward.

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G. Mark Burford, Cimarex Energy Co. - Senior VP & CFO [68]

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Yes. Betty, I'll just add on -- we have kind of highlighted some of our Culberson County lease operating expense per barrel. In that county, we were really -- we're close to $2 a barrel on a production expense. In the total Permian, we're only about $3.50. In this quarter we reported $3.34 per barrel on our production expense per barrel equivalent. And as you look into 2020, a blending of the Permian and Anadarko, we still expect to have a very competitive cost structure even with the Permian growing more rapidly.

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Operator [69]

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Your next question is from Brian Downey with Citigroup.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [70]

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Just a quick one from me. I believe you had recently tried an e-frac completion. Just wanted to confirm if that was correct? And any color you could provide on cost savings uptime versus conventional or stage efficiencies? I realized that may be a small sample size but curious on any comments and if you have future plans to continue using them when available?

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Joseph R. Albi, Cimarex Energy Co. - Executive VP, COO & Director [71]

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Yes, we did just finish one trial completion on 2 wells, and we have not finalized all the costs associated with it. So it's a little early for me to tell you the efficiencies that we may or may not have achieved with that operation. But we tried it because we want to learn more, and we are working with our main service provider to see how we may be able to better utilize the infrastructure and the electrical infrastructure that we have in particular, in Triple Crown to -- in the near to distant future transition ourselves into that realm, not only for cost savings but also from an emission standpoint. We see tremendous benefit to cutting any kind of emissions that would be associated with the fracs.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [72]

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Now -- so does that mean you're using the electric infrastructure within the field? Or are you still using field gas or, I guess, what would be the plan going forward?

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Joseph R. Albi, Cimarex Energy Co. - Executive VP, COO & Director [73]

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In this case, the frac that we tried was using fuel source not coming from our transmission lines, CMG. But going forward, what we're really seeing the true economic benefit where we see it being, is being able to provide our own power off our own grid. And that could substantially, we believe, lower the cost to do the e-frac.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [74]

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We own our own electrical distribution systems at Culberson County and in Reeves County. And like many others have used, that's probably where electrification will ultimately go rather than towing a powerplant around the oilfield, it probably makes more sense to have a power source that's stationary and just equipment that's mobile. We're studying this problem hard. We have a team digging into it. We're looking for some long-range solutions. And like so many things that we study hard, they look a lot simpler to us the less we know about it. And as we learn more and more, it becomes more complex. But we're convinced that this is a long-term direction that we want to go in and we're hard at work, just understanding the problem.

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Operator [75]

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The next question is from Nitin Kumar with Wells Fargo.

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Nitin Kumar, Wells Fargo Securities, LLC, Research Division - Senior Analyst [76]

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Just a quick one. I was looking at the Reeves County acreage in your latest presentation on Slide 12. There seems to be a slight drop of about 13,000 acres. Could you help us understand what happened there?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [77]

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Yes. If you look at our Reeves County map, there's some acreage in the far south of the county. That was an exploration play that we embarked upon a few years ago. It's actually off the map on Slide 12. We don't carry any locations on that acreage currently. We never have, and some of it was due to expire and we let it expire. We just couldn't make economic wells there. Do you want to add to that, John?

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John A. Lambuth, Cimarex Energy Co. - SVP of Exploration [78]

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We couldn't make any (inaudible).

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Nitin Kumar, Wells Fargo Securities, LLC, Research Division - Senior Analyst [79]

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So suffice it to say, it didn't meet the cost threshold. I guess a broader question. Tom, in the past, you've talked about the optionality and kind of having 2 basins, as I look at the initial guidance, clearly, you're favoring the Permian? And I get it why. But how far is the Mid-Con today from competing within your capital program?

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [80]

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Well, there -- we could easily put 30% or more of our capital in the Mid-Con next year. And that would be opportunities that compete heads up. We have a lot of things in the Mid-Continent that are competitive in today's environment. That said, as we've discussed in the past, we are in a, let's pull back and see what we can accomplish from an asset growth standpoint in the Mid-Continent. John and his team are hard at work looking for new areas and new landing zones. And we'd like to just beef up that asset and have it compete longer term. Do you want to comment on that John?

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John A. Lambuth, Cimarex Energy Co. - SVP of Exploration [81]

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The only thing I'd add is just what we're looking for is more depth to that inventory. So there's a more sustainability to it. And so we're putting a lot of effort to not just looking across our existing acreage positions that we have. And then furthermore, looking beyond that, because as someone said earlier in the call, there are opportunities now, and we're just looking for where are those opportunities where we think we have maybe an advantage to get in maybe at a reasonable price. And bring forward things that would compete for capital. So that's kind of where we're at right now with the Anadarko Basin.

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Operator [82]

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This concludes our question-and-answer session. I would like to turn the conference back over to Tom Jorden for any closing remarks.

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Thomas E. Jorden, Cimarex Energy Co. - Chairman, CEO & President [83]

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Yes, I want to thank everybody for participating. Also, thank you for your patience with our telephone interruption. We've had a lot of great questions, and I appreciate the thoughtful probing. We're looking forward to executing on what we've laid out today and updating you with our progress on future calls. So thank you again.

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Operator [84]

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The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.