Independence Contract Drilling Inc (ICD) 2014 Q4 法說會逐字稿

Good morning, and welcome to the Independence Contract Drilling's 2014 fourth-quarter and year end conference call. As a reminder, today's call is being recorded.

(Operator Instructions)

At this time for opening remarks and introductions, I would like to turn the call over to Phil Choyce, Senior Vice President and Chief Financial Officer of Independence Contract Drilling.

Good morning, everyone, and thank you for joining us today to discuss ICD's fourth-quarter 2014 results. With me today is Byron Dunn, Chief Executive Officer of Independence, and Ed Jacob, President and Chief Operating Officer.

Before we begin, I would like to remind all participants that our comments today will include forward-looking statements which are subject to certain risks and uncertainties. The number of factors and uncertainties could cause actual results from future periods to differ materially from what we talk about today. For a complete discussion of these risks, we encourage you to read the Company's earnings release and our documents on file with the SEC.

Additionally, we may refer on this call to non-GAAP measures. Please refer to the earnings release in our public filings for our full reconciliation of EBITDA and for definitions of our other non-GAAP measures. With that, I will turn the call over to Byron.

Thank you, Phil. Good morning, everyone, and thank you for joining us. Following our typical format, I will review quarterly highlights, current operations, and follow with an update on our outlook going forward into 2015, which I recognize is everyone's real focus. Phil will then discuss financial highlights for the fourth quarter and our view on the first quarter of 2015, and then we will take calls from participants.

Financially and operationally, Independence Contract Drilling delivered solid results in the fourth quarter of 2014, building on our established sequential improvements in financial and operating metrics realized throughout the first three quarters of the year. During the fourth quarter, we realized both year-on-year and sequential quarter record revenues, gross margin and EBITDA. On a sequential basis, we increased our rig operating days by 18%, our margin per rig operating day by 14%, and EBITDA by 37%.

During 2014, we added four new ShaleDrillers to our fleet at what we believe to be the lowest cost base in the industry, and by year end grew our fleet to 14 rigs, including 3 contracted rigs, which will deliver and complete in 2015. In addition, we updated a non-walking 100 series ShaleDriller to full 200 series status. We maintained contractual utilization of 100% with a solid and improving safety record exceeding IADC averages. Independence finished the fourth quarter with what we believe is the newest and most modern AC rig fleet across all US land contract drillers, public or private. Our oldest rig is less than three years old. Our fleet is exclusively made up of fast-moving AC drive equipment, with all but two rigs designed around our ShaleDriller 200 series integrated omni-directional walking system.

During 2014, we completed our transition to modular manufacturing. Importantly, these advanced build techniques have made Independence one of the lowest cost rig builders in the industry and provide us the flexibility to accelerator or suspend rig build tempo quickly and with very low costs associated with maintaining our build capabilities and knowledge base during a downturn.

Through the utilization of the rig's crew to assemble and fully commission newbuild rig modules, we can complete a new rig build cycle efficiently, about six months from decision to build to mobilization, and minimize the number of employees dedicated to rig construction. This capability provides ICD a strategic advantage in the contract drilling industry and a powerful compounding capital advantage relative to any contract driller who purchases third party rigs. When a new ShaleDriller rig leaves for its initial well deployment, the crew, having built the rig, is extraordinarily well trained, operating at a very high safety standard, with industry-leading up time performance on first well deployment.

Since our inception, Independence's cumulative fleet-wide uptime has been 98%. Our employees' expertise, commitment to safety, operational excellence and customer focus are a key differentiator and drive our leading safety and uptime record. ICD's committed to the selection, development and retention of the highest quality employee group in the industry.

So we had a great fourth quarter, great 2014. The question on everyone's mind is what does the current environment and the rest of 2015 look like? Well, the current contracting market is indiscriminate in its application of price pressure, and we expect substantial reduction in dayrates on new contract fixtures. At this time, we only have one rig idle. One rig. And that's a 100 series non-walking rig. Every other rig in our fleet remains on contract, with three contracted rigs on standby at full margin.

We're in discussion with customers on the four rigs whose contracts expire during the second quarter of 2015 and expect those rigs to recontract or work in the spot market at significantly lower dayrates than their current contracted rates. At this time, our overall revenue backlog is $153 million, with $84 million of that backlog to be realized in 2015, and I note that, that number's in excess of 2014 total revenue.

We're focused on capital efficiency and capital conservation. Our 2015 capital budget has been reduced to $54 million. That funds the construction of rigs 210, 211 and 212, all on new multiyear contracts; provides potentially for the upgrade of our two 100 series rigs to 200 series configuration and the decision on whether or not to proceed with those upgrades depending on market conditions and is still under evaluation. The $54 million provides for capital spares, maintenance CapEx, upgraded facilities at the Galati yard, as well as the purchase of various long lead time items critical to restarting our build program when market conditions improve.

The other four rigs previously scheduled for delivery in 2015 have been deferred, with delivery pushed back into 2016. And again, I want to note there's a fair amount of optionality in our 2015 build. As I mentioned, depending on market conditions, we are evaluating the possibility of upgrading our two remaining 100 series rigs to 200 series configuration, and we could accelerate at least one new rig back into 2015 from 2016 delivery date if conditions warrant.

Also, and as you would expect, we are very focused on our operating cost structure. As a modular manufacturer, we have complete control over our cost chain, and most construction-related costs automatically eliminate a rig delivery, so there's not much to reduce in the yard as our build tempo slows. We have a hiring freeze in place for corporate and operating departments, and we will continue to closely monitor and evaluate our operating cross structure as we move forward. Our balance sheet's strong. At year end, our net debt was approximately $12 million. And assuming our CapEx plans for 2015 are not reduced or expanded, we expect to finish 2015 with net debt of less than $60 million.

So in closing, I would like to take a minute to highlight key differentiating factors that set ICD apart from all of our public competitors. First, ICD is heavily differentiated from our competition. We are a focused builder and contractor of nothing but the highest technology, fastest moving, and most productive rigs in the industry, dedicated to industry-leading safety, rig uptime, rig productivity, and wellbore quality.

As such, at this time, we only have one rig down -- a 100 series non-walking rig. The rest of the fleet's on contract. All of our customers have told us that the ShaleDriller design is the rig of choice in an upturn and as pads become the standard development paradigm for cost-efficient reservoir exploitation by E&P customers, the contract drilling community will have to continue to upgrade to fleets offering the same functionality as the ShaleDriller. This will require a heavy and sustained continuation of the rig replacement cycle currently underway.

We expect the current downturn to accelerate the trends that form the basis for the initial formation of ICD. The very large investments made starting about 10 years ago by large independents, majors, integrated and knocks in North American unconventional resource, combined with the reservoir characteristics associated with those plays, including large aerial extent, reservoir homogeneity, form the strategic basis for the formation of ICD. These characteristics drove the initial E&P industry move to pad development as an effective and time-saving technique that was identified by investors in ICD as indicators of a growing secular move to the use of pads as the most economic resource development methodology.

We believe that the current commodity price weakness will accelerate pad development, with ever-larger pad well counts as part of cost control efforts by the E&P industry to lower overall F&D costs. The scale cost saving opportunities in pad field development encompass not only the manufacturer of more wellbore per rig per year assuming the application of pad optimal rigs, but incorporate better control of costs associated with frac and completion logistics, the use of field gas as a fuel source, and centralization of support employee base. We believe that larger pads offer nonlinear benefit aggregation regarding overall reduction in cost per well.

From a contract drilling perspective, new rig technology must be pad optimal, with regard to rig moving systems and be capable of drilling high-quality, nondeviated long lateral sections with the bare minimum of open hull time. To put all this in perspective, our ShaleDriller rig can drill a standard design, high-quality horizontal wellbore down 6,000 feet and out horizontally 6,000 feet in five days. On a pad to time between release from a drilled willing to commencement of drilling on the next well is three hours or less. This level of productivity, potentially 60 wells per rig per year in a pad application, is transformational for the economics of the North American E&P industry and highly disruptive to legacy North American drilling fleets.

In that regard, it's our expectation that in the coming recovery, mechanical rigs will be economically obsolete and relegated to niche opportunities. DC rigs will be in more or less the same situation. Non-walking AC rigs will fill the market segment currently occupied by DC equipment, and the fast-moving pad optimal AC rigs will become the industry standard offering.

Wrapping this up, as we move further through the ongoing North American rig replacement cycle, ICD has the rig of choice at an industry-leading cost base, with the right employee culture, outstanding uptime and safety statistics, and is established as one of the leading providers of high-impact contract drilling services. While the contract drilling market remains under pressure and has been indiscriminate to date with regard to across the board cost reduction efforts by our customers, all of our customers have told us that as the market settles and more discriminating planning processes take hold, ICD is a contractor of choice and the industry will adopt ICD strategy as pads dominate production programs.

We believe that ICD will return to a sustained growth trajectory later this year, and I want to point out that we're under no financial or operating pressure in any regard. Our focus will be on our cost structure. We will focus on adding new customers in this downturn and working in partnerships with customers who recognize the transformational value provided by Independence Drilling systems and crews. We will focus on conservation of capital achieved by the before-mentioned deferral of rig build and made by maintaining our ability to quickly ramp our rig build into the continuation of the North American rig replacement cycle. I'm confident that we are well positioned to effectively implement our proven business strategies and deliver on our promise of sustained growth and operational and financial excellence.

I want to take a moment to thank ICD's employees in the field, the yard, and in the office for their dedication to ICD's vision and values, their demonstrated commitment to safety and operational excellence. Our employees make us who we are, and I'm very proud of all of them. With that, I will hand the call back to Phil to discuss fourth quarter financial results and provide what we can in the way of first quarter 2015 guidance.

Thank you, Byron. I hope you all had a chance to see the press release we issued this morning. During the fourth quarter, we reported net income of $429,000 or $0.02 per share, excluding several items that were unrelated to our operations. As Byron mentioned, it was a record quarter for us in terms of revenue, margin per day, and profits.

To summarize the nonoperating items that affected our reported net income, first, we recorded a charge of $30.6 million, or $1.14 per share net of tax relating to the write-off of substantially all of our intangible assets. These related to our initial formation in 2012, and none of our drilling rigs were affected by this write-off. Going forward, this will result in a reduction in our depreciation and amortization expense of approximately $2.7 million per year.

Second, we recorded a net gain of $2.4 million, or $0.10 per share net of tax relating to a decrease in fair market value of a warrant. The warrant expired unexercised on March 2 of this year, and there will be no further gains or losses associated with this warrant in future periods. And third, we recorded a gain of $900,000, or $0.02 per share net of tax relating to the receipt of additional insurance proceeds associated with the claim made in the first quarter of 2014. We expect to receive the final insurance payment later this month and will recognize additional recovery in 2015 when received.

Now, I want to move on to the operating results for the fourth quarter. During the quarter, we realized record revenues of $23 million, and our revenues grew sequentially by approximately 20%. We ended the quarter with 921 rig operating days, representing an 18% sequential increase compared to the third quarter. On a revenue per day basis, we realized $23,944 per day in the quarter, representing a 3% increase compared to the third quarter. Our operating costs were $12,454 per day in the fourth quarter, which represents a sequential decrease compared to the prior quarter. The decrease related to strong operating performance at the rig level, as well as favorable outcomes associated with final rig ad valorem tax assessments. As a result of our significant improvements in both revenue and operating costs, we realized improvement in our operating margins during the quarter.

Our fourth quarter margin was $11,490 per day, which represented a 14% sequential increase compared to the third quarter. Fourth quarter SG&A expenses were $4.4 million, of which $1.1 million related to noncash stock based compensation expense. Sequentially, these costs increased due to us incurring public company costs for an entire quarter, and we also incurred additional expenses associated with final year end incentive compensation awards, which increased SG&A expenses by an additional $0.5 million over what we would consider our normalized run rate in our previous guidance. All of this resulted in us realizing adjusted EBITDA of $6.9 million during the fourth quarter, a 37% sequential increase compared to the third quarter.

Fourth quarter depreciation expense was $4.6 million. This includes $700,000 of intangible amortization that will not continue in 2015. With respect to taxes, during the quarter we recorded a tax benefit of $1.8 million, which equated to an overall effective tax rate of approximately 6.8%, which was lower than what we would normally expect due to evaluation allowance placed on our deferred tax assets during the quarter associated with the write-offs that I previously discussed.

Moving on to our balance sheet, at December 31, 2014, we had cash on hand of $10.8 million and $22.5 million of debt drawn on our $155 million revolving credit facility. Our borrowing base under the credit facility was approximately $115 million at year end, which reflected an entire reappraisal of our rigs conducted by our lenders in light of declining market conditions. Our borrowing base will increase when each of our 2015 newbuilds commence operations. The facility does not mature until 2018.

Now I want to turn to 2015 and our outlook. As Byron mentioned, as a result of declining market conditions, our base plan for next year is to complete the three rigs that we currently have contracted and defer all other newbuild activities until market conditions improve. As a result, our planned CapEx for 2015 has been substantially reduced. Overall, our 2015 CapEx budget is $54 million.

This includes costs associated with completing the three rigs under construction, completing the buildout of our critical spare inventory, and maintenance CapEx. In addition, the budget includes approximately $13 million allocated to upgrade our two non-walking rigs or completion of an additional rig. No decisions have been made on upgrades or additional rigs at this time and will not be made until later in the year, as we gain greater visibility on market conditions.

As Byron mentioned, our current backlog is $153 million, of which $84 million should be realized in 2015. All of this backlog is backed by take-or-pay term contracts. Our 2015 backlog is higher than our 2014 results, not only with respect to overall revenue dollars, but also in contracted rig years. There will be variation between our actual revenues in the backlog based on how many standby days we have during the year, which can reduce our top line number, but not our overall profitability. Overall, this 2015 backlog equates to 9.2 rig years worth of work in 2015. By comparison, in 2014 we had an average of eight rigs working during the entire year.

Given market conditions, it is very difficult to predict how much revenue and margin we may earn from potential revenue days not in backlog. Our overall costs per operating day for FY14 were approximately $12,800 per day. We do expect this to increase in 2015, as we move from the 100% contractual utilization we experienced in 2014 to something less than that during 2015. We also will experience some additional operating costs associated with preparing our one idle rig for stat and its potential upgrade later in the year.

Our operating costs per day in this environment are going to be lumpy, and we expect could fluctuate between $13,000 to $14,000 per day during any particular quarter in the year, based upon the operating environment and overall rig utilization during that particular quarter. On SG&A, we see our annual SG&A costs to be in the $10.5 million to $10.8 million range for the year, with noncash stock-based compensation adding another $3.8 million to $4 million for the year on top of that. With respect to taxes, our NOL balance is in excess of $30 million on a tax affected basis. However, for accounting purposes, we now have 100% valuation allowance on the entire amount that we do not plan to release during 2015. With our sizable NOL balance, we do not expect to be a federal taxpayer in 2015.

We are not in a position to provide full-year financial guidance for 2015, but with respect to the more specific information regarding our first quarter, we currently have four rigs earning standby revenue rates, which can change rapidly. This makes our top line numbers during the quarter more difficult to predict. During the first quarter, we expect our revenue days to range between 920 and 940 days. We expect our margin per revenue day to range between $9,500 and $10,250 per day. The expected decline in margin per day from the fourth quarter relates to expected cost increases associated with our one idle rig and more normalized well level costs compared to the fourth quarter.

Other operating costs not reflected in our margin per day statistics will be in the range of about $300,000 in the quarter. First quarter SG&A will include year end audit and annual meeting costs and should be in the range of $3.7 million to $3.9 million, including noncash stock-based compensation of approximately $1.1 million. Depreciation in the first quarter will be in the range of $4.2 million to $4.4 million. Interest expense does not capitalize during the quarter, will be in the range of $150,000 to $200,000.

Wrapping it all up, we believe we are in excellent shape as we move forward into 2015. We have an existing [track] contractual backlog that allows us good visibility to implement our operating plans with a high degree of confidence and to grow our cash flows compared to 2014 and to maintain responsible financial ratios. From a financial liquidity perspective, we have right-sized our Company and spending plans to maintain low debt level and maintain a very healthy credit profile. At the same time, we are maintaining the flexibility within the confines of our announced 2015 CapEx budget to introduce a fourth ShaleDriller rig later in 2015 or operate our two non-walking rigs based on how things develop during the year.

And with that, I will turn the call back over to Byron.

Thank you, Philip. I have no further comments at this time, so operator, would you open the line for questions, please.

(Operator Instructions)

And the first question comes from Jeff Tillery with Tudor Pickering.

Hi, good morning.

Hi, Jeff.

Byron, could you talk about -- as the first half of the year plays out, obviously the four rigs that are rolling off contract, could you just describe qualitatively what discussions are and just the handicapping the degree to which somewhere between zero and four those keep working in the second quarter?

Sure. Let me direct that to Ed Jacob. Ed is in touch with this to a great degree, and he can answer that.

Morning, Jeff.

Morning.

That's the big question, isn't it? There are ongoing -- we've had multiple ongoing discussions for opportunities in the second half of the year for the four rigs. I'm comfortable that if you ask me from one to four, I'm comfortable that we could get at least two back to work in the second half of this year.

Currently, there is no spot market. We don't -- nobody's doing anything right now, but we are seeing, are having conversations and multiple inquiries regarding rig availability for primarily the 200 series rigs going forward for the second half of this year, which I believe is a positive indicator of what our customers believe is going to be the start of an improvement in the market for the second half of 2015 and into 2016.

And Jeff, let me just note that the conversations that Ed and his team are having are not only with existing customers, but with potentially new customers who are very, very large independents.

And then Byron, the discussion around net debt as this year plays out, as you're starting the year with on the order of $12 million and I think you said in the prepared remarks to end the year less than $60 million only spending $55 million of CapEx. It would seem like if that's certainly a conservative number, that it would seem hard to end the year at more than $60 million debt unless the CapEx increases. Am I--

That would be correct, Jeff.

That's the highest number we expect, Jeff. We've got some monies that have been allocated to continue to build additional new rigs in 2015 or to upgrade rigs in 2015.

We won't spend that money if we don't think we can get an adequate return on that investment. So there's probably room for that CapEx number to move down, and what we put out is the high end of the range.

Okay. So said another way, for you to hit that $60 million net debt number, it's probably because good things are starting to happen so you're spending more money, is that correct?

Yes, that would be correct, yes.

Okay. And then last question I had, just on the three rigs that are to be finished here in the first part of the year, how much is left to be spent specifically on those, those three rigs?

For those, for those rigs that's in the $54 million?

Yes.

Okay. I can get that for you. It's going to be $41 million.

Perfect. All right. Thank you guys, very much.

Thank you, Jeff.

Thank you. And the next question comes from Ole Slorer of Morgan Stanley.

Thanks, and congratulations with the strategy that seems to be working despite little help from the market.

Thanks.

Just getting back to the balance as the near term is all about understanding the downside here, so you said $41 million and then maybe another [$5 million], [$6 million] or so I would guess on the upgrade on the 100 to 200. What would your fleet consist of at the end of the year associated with that $60 million debt? How many remaining 100s will you have and what will the rest of the fleet look like?

If we spent the entire CapEx amount, we would end the year either with 14 rigs, all of them being 200 series, or 15 rigs with 2 remaining 100 series. So -- or I guess there could be something in between.

We have the flexibility to build an additional new 200 series rig or to upgrade the two 100 series, or to do some combination of those things. So the fleet would not be bigger, I don't think, in 2015 unless the market did something we don't expect it to do.

Okay. I was trying to figure out the debt per rig. So it's still pretty conservative. If there is no spot market, you mentioned that you expected maybe some of the rigs to move onto shorter term contracts.

Would it be possible for you at all to discuss the type of pricing that you would expect in the, let's say if you were focused on just keeping the rigs warm in a market where the others are trying to do the same? Are we looking at something close to cash breakeven, or how should we think about it?

This is Ed. Typically in these cycles, the contracts start off in a well-to-well contract, and then we will move to six-month term, and then a year term and two years and such. I would just be guessing, but the feel that I have from talking to customers, and reading reports that you and your colleagues generate, I would be surprised to see the 200 or the walking rigs with the bifuel system, 75, 100 pressure system, I think those are going to maintain there in the 20%s.

20%s?

18.5% what I think would probably -- I'm going to guess is the low. I don't see those rigs going to cash breakeven. However, I think if you have -- if you are highly leveraged to legacy fleets, I think those will go to cash breakeven and are probably quickly on their way there now.

And when we think about those, say, low 20%s rates, I presume we should not use the 65 days to calibrate that. Would there be some downtime in between wells, given they're well-to-well, or do you expect that could work continuously?

I think even though they are well-to-well contracts, they will typically give you three wells and then you can estimate the term on that. But I think that once a rig gets out into the field, I don't think our customers are going to pick up additional rigs, nor will we take a rig out of an idle status unless there's a longer period of work, even that appears to be on the horizon from that operator. So somewhere between 50% and 85% utilization to me has historically been what I'm used to seeing in that environment.

Okay. Thanks, Ed. That makes sense.

Is that good?

That's perfect.

Thank you. And the next question comes from Rob MacKenzie with IBERIA Capital.

Thank you, guys. Byron, I guess a strategic question for you. If you were to commit to building an incremental 200 series rigs or upgrade the 100 series rigs, would you do that on spec or would you look to have a term contract in place first?

Okay. So there's not a simple answer to that question. There's a lot of other moving parts. It would depend critically on our view of the environment out six months to a year.

We don't want to miss an upcycle, but we don't want to get sucked in by a head fake. It would depend on the dayrate associated with it, and certainly on term, we would do it.

I guess the question is would we do it without term? And I can't answer that question. It would depend on those other variables.

I will say that we started the Company building these things on quasi spec, where everything we ever built was contracted before it left the pad. But this is a different world, and I think we will probably err to the side of caution, if that's helpful.

That is. I guess my next related follow-up is given where you see your cost structure evolving to this year, what rate would you need to hit your return on capital hurdles to build an incremental 200 series rig?

Depends on term, but something, something higher than 18.5%. And there's other things in term. There's a lot of levering. We look at MPV, Rob, there's a lot of levers there.

There's can we tie -- can we form a strategic relationship and tie an expansion of our fleet into a particular client's drill program as part of some rate concession on a rig? We will look at all those things obviously. So -- but we're very MVP focused, and we're not going to do things that destroy value on an MVP basis.

Right. It would seem to take obviously much higher rates than, say, 18.5% to incentivize new build in here. Coming back to your earlier comment about the necessity of building more pad rigs, I guess I'm struggling a little bit with the math of an operator taking a pretty darn capable skid rig at 18.5% versus paying high 20%s for a pad optimal rig.

I threw 18.5% out as an example of what we would not do. And I don't want to be a lot more specific than that for obvious reasons. But from a strategic standpoint, we see continued bifurcation of the market.

We see continued demand for pad optimal rigs and ever-larger pads in excess of the current North American fleet's ability to supply them. The situation right now obviously doesn't reflect that, but as Ed mentioned, we expect to be moving back into that environment later in this year and certainly next year and the dayrates will reflect that.

Okay, thank you. My final question, if you wouldn't mind, perhaps Philip, going over some of the moving parts in your termination clauses for your rigs.

You mentioned they are all on take or pay contracts. I'm sure some of them had different types of contracts. Can you give us a summary of that?

Typically we will receive the operating rate or the dayrate or the move rate, which would be a slight discount to that for the remainder of the term. It would be paid in a lump sum on the day they term.

I think we have one contract that we would pay the margin, we would receive the expected margin with no mitigation requirement on our part. So those are what they look like.

And the conversation you said you were having earlier in the call, is that around restructuring rate, or terminating the contract? And I presume if it's restructuring the rate, you would probably extend the term for a lower rate?

No. The conversation, the comments I made regarding conversations taking place are conversations regarding rig availability for projects that our customers are seeing in the second half of this year. We are -- one of the things that we have committed to not doing is giving up any of our financial position on any of our existing contracts. Now, I know that there's -- this industry's been pretty good about extending terms for lower dayrates or getting additional equipment, additional rigs, but the whole point is you have to maintain the financial piece of the transaction and not give any of that up.

Great. Thank you very much. That does it for me.

Thank you.

(Operator Instructions)

We do have a question from Daniel Burke with Johnson Rice.

Good morning, guys.

Hi, Daniel.

Good morning.

Can you remind me, what -- I know the industry's in flux, but what level or what count of scheduled contract expiries do you have in second half 2015?

The second half of 2015? We've got the four that are -- that's in the first half. Nothing else expires in the second half of 2015.

Okay. Perfect. Philip, I appreciate the revenue backlog figures. Understand some of the implications around standby days there. But what tale -- within that figure, what level of tale do you all have in 2016 -- excuse me, 2017?

2017 in our backlog?

Yes.

I think the backlog in 2017 is going to be in the, about -- it's probably three or so rig years of backlog.

Okay. That's helpful. And then the last one, ICD has a focus on the Texas market, West Texas, but when you look at the discussions with customers and seeking to keep rigs warm stacked, do you take a more expansive view of the geographies you contemplate operating in?

Look, our target market is way beyond West Texas. We target Texas and all the contiguous states. We've operated in the midcontinent. We've operated in the Granite Wash. We've operated in the Eagle Ford.

So anything that's in Texas or the contiguous states it our target market. That encompasses most of the drilling for our type of equipment in the United States, and it also encompasses where we expect growth in demand for rigs to occur.

I think there's some research out that indicated that 80% to 90% of the expected increase in demand for new rigs between now and 2025 was going to occur in our target market. We have no interest in expanding out of that area right now. There's no particular operational or financial reason to do so.

Okay. Well, I appreciate the answer, Byron. Thank you.

Thank you. As there are no more questions right now, I would like to turn the call back over to management for any closing comments.

Thank you all for joining us. We know it's trying times. We'll keep you all apprised of our progress, and we're dedicated to growing shareholder value as a team and we look forward to working with you in the future.

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