Unit Corp

OTC:UNTC

Earnings Call Transcript 2019-Q1

[Operator]

Welcome to the Unit Corporation's First Quarter 2019 Earnings Call. My name is Paulette, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded.

During the course of the conference call today, the speakers may make statements that constitute projections, expectations, beliefs or similar forward-looking statements. The company's actual results could differ materially from the results anticipated or projected in any such forward-looking statements. Additional detailed information concerning the important factors that could cause actual results to differ materially from the information given today is readily available in today's press release under the heading Forward-Looking Statements.

Additionally, during the conference, the company will be discussing certain non-GAAP financial measures. The reconciliation of those non-GAAP measures to GAAP measures can also be found in today's press release. This document is available on the company's website.

I will now turn the call over to Larry Pinkston, CEO and President. Larry Pinkston, you may begin.

[Larry Pinkston, executive]

Thank you, Paulette. Good morning, everyone. Thank you for joining us this morning. With me today are David Merrill, Les Austin, Frank Young, John Cromling and Bob Parks. Each will be providing you with updates about their areas of responsibility, and then we will take questions at the end of the call.

The first quarter of 2019 was influenced by several different factors. David and Les will be expanding these items as they provide you with their comments. Our plans for 2019 for drilling activities to most -- to be mostly accomplished during the first half of the year. We are currently operating 6 rigs in our exploration and production division and plan to begin reducing our operated rig count in the third quarter. We will monitor commodity prices, drilling results and debt levels at midyear to determine the appropriate level of activity -- of drilling activity for the second half of the year.

Our oil and gas production should remain relatively flat during the first half and then ramp up in the second half of the year. Commodity prices during the quarter were very volatile. Crude prices bounced back prior to year-end levels. However, natural gas prices continue to deteriorate during the first quarter. The differentials on natural gas pricing continue to widen in Western Oklahoma and the Texas Panhandle. We believe these differentials should start to improve during the second half of the year as new infrastructure is put into place. We have altered our drilling plans for the year due to these wide differentials.

I'll now turn the call over to David Merrill.

[David Merrill, executive]

Thank you, Larry. There has been a lot of publicity around the Permian natural gas takeaway constraint and certain indexes such as Waha has gone temporarily negative. That issue, however, is not isolated to the Permian basin. Natural gas associated with crude oil production is seeking any possible outlet and as such some has moved into the mid-continent region, negatively impacting prices in Western Oklahoma and the Texas Panhandle and in some cases, leading to takeaway constraint. Releases on the horizon was a Gulf Coast Express Pipeline, a 2 Bcf per day pipeline project targeted to be completed in late 2019 or early 2020. Offering further relief is the Midship Pipeline, a 1.4 Bcf per day pipeline scheduled to be completed late this year, going for Western Oklahoma to Bennington, Oklahoma for further connection to East Texas and Louisiana.

As Larry has discussed, weak natural gas prices have heightened negative differentials, validates the approach we follow by having multiple core areas for our oil and natural gas segment. With what we believe our temporarily reduced rates return in our Texas Panhandle core areas, we have relocated our rig activity from the Granite Wash play to Western Oklahoma where we will target more oil from prospects.

The unanticipated shut in of the third-party processing plant for our East Texas Wilcox play production significantly impacted first quarter production. Without the field shut in, daily production would have increased 1% quarter-over-quarter.

Furthermore, Wilcox production, with approximately 40% liquids and 60% natural gas composition, is priced at some of the best index prices of all our production. The third-party processing plant is now up and running at normal rates, and we expect the recovery should improve with the completed repairs that were made.

Our contract drilling business placed 2 new BOSS drilling rigs in the service during the first quarter, bringing our BOSS rig count to 13. We continue to pursue long-term contract opportunities to begin building our 14th BOSS rig.

The midstream business saw a significant increase in gathered volume primarily from the new pad coming online at out Pittsburgh Mills gathering system. Further growth is anticipated as the new reading processing plant has recently come online at the cash-in systems, and incremental volumes have begun to flow.

I'll now turn the call over to Les Austin.

[George Austin, executive]

Thanks, David. We reported a net loss attributable to Unit for the first quarter of $3.5 million or $0.07 per diluted share. Adjusted net income attributable to Unit for the quarter, which excludes the effect of noncash derivatives, was $4.5 million or $0.09 per diluted share versus $13.8 million or $0.27 per diluted share in the fourth quarter of 2018. The primary factors contributing to the quarter-over-quarter change included production declines from a third-party gas processor plant shut down, 9% lower natural gas prices, 18% lower natural gas liquid prices and lower rig utilization, somewhat offset by early termination fees in the contract drilling segment. Our non-GAAP financial measure reconciliation is included in our press release.

For the oil and natural gas segment, revenues for the first quarter decreased 19% from the fourth quarter of last year with lower natural gas and NGL prices, as previously discussed. Equivalent production also decreased 5% in the first quarter from the fourth quarter of last year due to a third-party gas processor plant shut down, resulting in lost Wilcox production of 1,65,000 barrels of oil equivalent.

Operating cost for the first quarter increased 5% over the fourth quarter of last year primarily due to higher saltwater disposal and the absence of production tax credits.

For the contract drilling segment, revenue for the first quarter decreased 3% from the fourth quarter of last year due to 5% fewer rigs operating in the quarter partially offset by increased day rates and a $4.8 million in early termination fees.

Operating costs for the first quarter were 12% lower compared to the fourth quarter of last year primarily due to less rigs operating.

For the midstream segment, revenues for the first quarter decreased 6% from the fourth quarter of last year, primarily due to decreased natural gas, natural gas liquids and condensate prices, somewhat offset by increased gas volumes gathered.

Operating cost for the first quarter decreased 9% from the fourth quarter of last year because of the decreased purchase prices.

We ended the first quarter with total cash and cash equivalents of $3.9 million and long-term debt of $685 million. Long-term debt consists of $645 million of senior subordinated notes, net of unamortized discounts and debt issuance cost and $40 million outstanding on Unit's revolving credit agreement. The Unit credit agreement borrowing base remained unchanged at $425 million, and our $200 million superior credit facility remained undrawn at the end of the first quarter. Our net leverage ratio was 2x at the end of the first quarter.

At this time, I will turn the call over to Frank for our oil and natural gas segment update.

[Frank Young, executive]

Good morning. Daily production for the first quarter averaged 45,800 barrels of oil equivalent per day, a decrease of 1% compared to first quarter 2018 and 2% compared to the fourth quarter. Production was hurt by unplanned downtime associated with emergency repairs of a third-party processing plant that forced 90% of Unit's Wilcox wells in the Gulf Coast area to be shut in for 14 days, reducing quarterly production by 165,000 barrels of oil equivalent. The processing plant was back to full operational capability in early April. Without this downtime, daily production would have been approximately 47,600 barrels of oil equivalent per day, roughly at 3% and 1% increase over first quarter 2018 and fourth quarter 2018 daily production, respectively.

As David mentioned, during the first quarter, we suspended Granite Wash drilling operations in the Texas Panhandle in response to the current low gas price environment and our expectations that gas prices will improve later in 2019 when Cheniere's Midship Pipeline and Kinder Morgan's Gulf Coast Express Pipeline come online. These pipelines should decrease the amount of gas competition in the Texas Panhandle, coming west from Oklahoma STACK and SCOOP plays and Northeast from Texas' Permian basin, providing us better Granite Wash drilling economics in 2020.

Our land position in this area is largely held by production, allowing us to drill when pricing warrants.

We have 3 extended lateral Granite Wash wells in various stages of being completed at the end of the first quarter with all expected to come online during the second quarter flowing to Superior, Unit's midstream subsidiary.

In conjunction with suspending drilling in the Texas Panhandle, we are accelerating drilling operations in Western Oklahoma to take advantage of the better economics associated with the more oil-prone nature of our Thomas Field Red Fork play and our SOHOT Marchand play, both located within our Penn sands prospect area.

Unit is currently running 4 rigs in this prospect area, with expectations of bringing 10 new wells online during the second quarter or early third quarter. Of the 10 new wells, 4 are in various stages of completion, 4 are currently being drilled and 2 are remaining on the drilling schedule.

During the first quarter, Unit completed 1 Red Fork well with a 4100-foot lateral that had an IP30 of approximately 300 barrels of oil equivalent per day with 65% being oil.

Although we were pleased with the oil component percentage, typically we would drill a longer lateral located in better part of the Red Fork reservoir than this well. However, the commitment to drill this location was part of the acquisition in 2018 of acreage in the Thomas Field.

Unit's initial Red Fork well in the Thomas Field, which came online in September of 2018, continues to exceed our expectations. On a gross basis, the well has cumulative production of 325,000 barrels of oil equivalent, and the latest production is 475 barrels of oil per day and 3.9 million cubic feet of gas per day. While we continue to have high expectations for the Red Fork play, our top curve is based on a limited data set of 4 horizontal wells. However, we will be gathering additional data throughout the year allowing us to provide further clarity of what to expect from future wells.

Unit also completed 1 Marchand well with an IP30 of 175 barrels of oil equivalent per day with 70% being oil. This well was more than expected due to the reservoir being thinner at this location than anticipated.

Overall, our Marchand well results have continued to be outstanding, and then our top curve for a 5,000-foot lateral remains in the 600,000 barrels of oil equivalent range with 65% of that being oil.

We have been successful on -- in adding approximately 8,200 net acres at an average price of about $900 per acre within the Penn sands prospect area since the beginning of the year. This acreage focuses on oily targets and adds approximately 19 operated and 12 nonoperated potential horizontal locations into our drilling inventory.

In our Gulf Coast area, we drilled 3 development wells in the Gilly Field that are currently in various stages of completion. We are also continuing delineation of our Shoal Creek prospect, discovered in 2010 when we drilled the Blackstone G1 exploration well.

After seismic reprocessing, the prospect appeared to have significant upside, and we drilled the Blackstone G2 encountering multiple stacked pay intervals in the lower Wilcox. After being completed in mid-December and 3 of the lower stacked pay intervals, production is varied between 6 million and 8 million cubic feet equivalent per day with 25% of that being oil during the first quarter of 2019. The size of the Shoal Creek prospect will be further evaluated in the second quarter with the drilling of the Blackstone G3 that, if successful, will lead to more delineation wells.

Also during the quarter, we drilled the Wing north exploration well, and while it found the objective to pay interval, the current production of 1.7 million cubic feet per day has been disappointing. However, this well improved our geologic understanding of this area and resulted in the identification of an additional high potential prospect.

In our Cherry Creek prospect, we drilled the first delineation well, the Wolf Pasture #1, located approximately 7 miles southwest of the Gilly Field. Fracture stimulation of the lower Wilcox play interval in this well is scheduled for the second quarter with the potential to add additional pay later in the year. We are optimistic about the exploration program in the Gulf Coast continuing in the second quarter, with not only the activity at Shoal Creek and Cherry Creek prospects, but also with the drilling of our Menard Creek prospects. These prospects provide Unit with exposure with a significant resource potential. We continue to be successful on executing our strategy of adding acreage in prospects at lower cost in our Western Oklahoma and Gulf Coast operating areas that provide drilling inventory, a competitive planning and development cost and cash flow margins. Our drilling activity is concentrated in the first half of the year, and we will begin reducing activity levels throughout the latter half. Longer term, we will continue to evaluate both organic and acquisition opportunities in areas that provide competitive cash margins.

At this time, I'll now turn the call over to John for the drilling company update.

[John Cromling, executive]

Good morning. The commodity pricing fluctuations during the fourth quarter of 2018 continued during the first quarter of 2019, thereby, affecting our drilling rig activity. We were able to maintain a relatively stable number of active rigs throughout the quarter. We began the year by placing our 12 BOSS rig in service in Wyoming under a long-term contract and also extended the term contracts on 2 additional BOSS rigs already drilling for the same operator.

In mid-February, we completed our 13th BOSS rig, and it is operating in the Permian basin. The regional operator for this rig decided to reduce the rig count due to commodity pricing and terminated the contract before completion of the rig. This contributed to most of the early termination fees we collected during the quarter. Because of the reputation of the BOSS rigs, we obtained a new contract almost immediately and did not suffer any loss time.

We began the year with 32 rigs operating, rising to a high of 34 rigs and finishing the quarter with 32 rigs operating. We presently have 31 rigs operating. All 13 of our BOSS rigs are operating and 9 of them are on term contracts.

The average day rate for the first quarter was $18,339, an increase of $292 per day over the fourth quarter. The average total daily revenue before intercompany eliminations was $20,339, an increase of $2,104 over the fourth quarter. Our total daily operating cost before intercompany eliminations increased by $575 for the first quarter as compared to the fourth. The increase was primarily due to labor cost due to certain employment taxes rolling over and higher indirect cost resulting from workmen's comp settlement.

The average per day operating margin for the first quarter before elimination of intercompany profits was $7,376, which is an increase of $1,517 over the previous quarter. Our non-GAAP reconciliation can be found in today's press release.

Interest in our BOSS rigs remains very high, and we are evaluating the possibility of another long-term contract to grow our BOSS rig fleet. We will also continue to upgrade SCR rigs. However, at this time, this will be restricted 2 particular items on rigs rather than a total refurbishment of a rig. It is important to note that all of these projects are being financed by operating cash flow and within our CapEx budget. We continue to be optimistic in our opportunity to grow during 2019.

This time, I'll turn the call over to Bob for the Superior Pipeline update.

[Robert H. Parks, executive]

Thank you, John. Following at an outstanding year in 2018, the midstream segment is off to a good start in the first quarter of 2019, producing solid financial results. We had a 14% increase in total throughput volume over the fourth quarter of 2018, driven by adding 7 new long-lateral wells to our Pittsburgh Mills system in the Appalachian area and continuing to expand and add new wells to our central Oklahoma Cashion facility.

Operating profit before depreciation was $13.1 million for the first quarter of 2019, which was a 6% increase over the fourth quarter of 2018. This increase was due to the additional throughput volumes from our Pittsburgh Mills and Cashion facilities. We invested approximately $15.3 million in capital projects during the first quarter of 2019. The majority of these expenditures were spent at our Cashion facility, extracting the new 60 million cubic foot per day reading plant and by continuing to expand and connect wells for our Cashion system. Additionally, some of the capital expenditures were to complete the connections of this new 7-well pad to our Pittsburgh Mills system.

I'll now discuss several of our key midstream assets. At our Pittsburgh Mills gathering facility in Pennsylvania, during the first quarter of 2019, our average total gathered volume increased to approximately 197 million cubic feet per day. This increase in gathered volume was due to adding the new 7-well pad during the first quarter of 2019. The construction of the new pipeline to connect this pad was completed in January, and 2 of the wells began production in late January, and the 5 additional wells began production in the first week of February. The initial production from these new wells increased our total throughput volume by approximately 115 million cubic feet per day, and we expect them to continue to produce around 100 million cubic feet per day for the next several months. This new well pad is connected to our Kissick compressor station located on the southern portion of our gathering system, where we deliver the gas into a DTI pipeline.

At our Hemphill facility in the Texas Panhandle, the average total throughput volume for the first quarter of 2019 was approximately 73 million cubic feet per day, and total production of natural gas liquids was approximately 251,000 gallons per day.

During the first quarter, we did not connect any new wells to this system, but we're in the process of connecting the 3 new Unit Petroleum Buffalo Wallow wells in the second quarter.

At our Cashion processing facility located in central Oklahoma, the average throughput volume for the first quarter of 2019 increased to approximately 54 million cubic feet per day, and natural gas liquids production increased to approximately 264,000 gallons per day. This continues to be an active area. And during the first quarter of 2019, we connected 7 new wells to the Cashion systems. We're continuing to expand our Cashion system and expect to connect additional wells during the rest of 2019. With the reading plant addition, our total processing capacity on our Cashion system increased to approximately 105 million cubic per day.

In summary, we are pleased with both the operational and financial results for the first quarter of the midstream segment. With the addition of new well pad in the Appalachian area and with the continued expansion of our Cashion system, we are producing positive results in several key areas. Additionally, having established a $200 million stand-alone credit facility for Superior, we are well positioned to continue to expand and grow the midstream segment during the rest of 2019.

I will now turn the call back over to Larry for his final comment.

[Larry Pinkston, executive]

Thank you, Bob. As we closed out another quarter, our 3 business segments continue to progress in each of its position very well as we move through the remainder of 2019. The advantages of our oil and natural gas segment portfolio will allow us to direct capital efficiently. Our contract drilling business continues to see opportunity to grow our BOSS drilling rig fleet. Our midstream segment has been able to take advantage of organic growth opportunities, while we continue to see growth through prudent acquisition. While we continue to see many opportunities, we remain committed in maintaining our disciplined approach of keeping our capital spending in line with anticipated cash flow. This will ensure that we maintain a strong financial profile today and tomorrow. I'd like now turn the call over for questions.

[Operator]

[Operator Instructions] And our first question comes from Marshall Adkins from Raymond James.

[J. Marshall Adkins, analyst]

I want to start on the drilling rig side. John, the -- help me understand where you see demand shaping up for rigs, both in Q2 and the back half of the year?

[John Cromling, executive]

Marshall, that's hard to guess right now. As we have alluded to and several other comments already, the drilling rigs will follow, of course, the operator's activity. We know that subdued right now because of the constraints on the natural gas. So for the next quarter, I think this will be very much the same as what we've seen in the first for the mid-continent and even for the Permian. Seems like Rocky Mountains, Wyoming, North Dakota probably stay pretty constant, maybe a little bit better. Then we're hopeful, as it has been mentioned about the pipelines relieving the differential on the gas that we will see activity increase again in the mid-continent region and even in the Permian.

[J. Marshall Adkins, analyst]

Okay. Larry, let me fill that kind of same directional question. You -- I mean, you have seen it from a lot of different perspective. Let's just say, oil stays here in the $60, $65 range. We're hearing all kinds of different opinions right now out there from the broad-spectrum with E&P and services. And clearly, there's capital that's spent on a lot of the public E&P's, but the smaller private guys seemed to be -- I mean, obviously, the economics are very good, and they're looking it increases in the back half of the year. How do you see it playing out? Let's say, if oil stays here in the $60, $65 range for the back half of the year?

[Larry Pinkston, executive]

I think, you'll see for the all directed rigs. I think you could -- you see a steady-to-upward movement on rig utilization. I think second half is going to be somewhat soft, but -- I mean, the second quarter. Second half, I think, is going to be a stronger quarter. And if we'll get some stabilization in the out months on crude, it's not so much that crude is $60 today, it needs to be $60 for next year. And where you could actually lock in some prices for those out years. And when that starts to happen, I think you'll -- then you'll see a much more rapid increase in the oil prices. That's my thought in oil, Marshall.

[J. Marshall Adkins, analyst]

Yes, that's helpful. Last, I'm going to shift gears over to Frank. Frank, could you give us some indication of where your hedging sits today? Number one. Number two, I'd like to get some thought -- I mean, obviously this plant being off-line being the quarter pretty good. Is this something that was really totally all base? It's not going to happen again or should we kind of start modeling in possibilities or things like this in the future?

[Frank Young, executive]

I'll answer the second question. The question on hedging, I think, Les will answer. But as far as the plant goes, we have modeled a 5-day shut in into our budget projections. We had modeled that occurring in July. And the issue that happened with the plant was discovered. They decided to move their routine maintenance part of the plant up some. And when they did that, they discovered this problem. The problem that they discovered resulted in them having to get equipment fabricated in Canada. And that's a several days to get done, and this still happened at the piece of equipment that they needed. They didn't have a replacement or the plant couldn't operate without it. It was the A-main tower. So we don't expect anything like that to happen again. But you're correct in saying that in general, we'll see every other year. They'll have some kind of plant maintenance that we'll -- that we generally will plan for in our budget.

[George Austin, executive]

And Marshall, we did file our 10-Q earlier before the call. And in there, we disclosed at the average production rate that we had in the first quarter, we're about 52% hedged for the balance of the year on oil and about 51% hedged for the balance of the year on natural gas.

[J. Marshall Adkins, analyst]

How about 2020? Anything big in 2020?

[George Austin, executive]

No. Nothing really in 2020.

[Operator]

Our next question comes from Neal Dingmann from SunTrust.

[Neal Dingmann, analyst]

I just have a broader question. I know you guys or maybe for you Frank. Definitely, the focus on increasing the oil content. I'm just wondering, and when you kind of look at the breakdown of the components today? I mean, is that something that may start to shift a bit noticeably by the end of the year? I'm just wondering how the pace of -- again, it seems like you're certainly actively addressing this. I'm just wondering, when we'll start to see some changes on that overall mix?

[Frank Young, executive]

Neal, our current first quarter production rate for oil comprised about 16.7% of our total flow stream. And as the year goes along, we expect to see a significant increase really beginning in the third quarter and continuing into the fourth quarter. I expect to see our daily production rate increase in excess of 20% as the year -- as we go through the year.

[Neal Dingmann, analyst]

And Frank, externally, just to me to add on to that, unlike there is a nice pick up in the Penn sands. Are there other additional pieces you're seeing out there that you can continue to bolt-on here remainder of the year?

[Frank Young, executive]

Yes. We have other areas identified, and we're in talks with several companies to add that acreage. They're all, like you said, bolt-on smaller type of deals that we were -- but together, like in the first quarter, they can make a significant difference to our drilling inventory.

[Neal Dingmann, analyst]

Okay. And then just lastly, maybe turning to -- go ahead, I'm sorry.

[Frank Young, executive]

No, that's all I had.

[Neal Dingmann, analyst]

Okay. And then just one last question maybe for John. John, your thoughts on -- nice move on the rig operation margins per day. I'm just wondering if you could kind of give us what you're seeing quarter-to-date? How you're thinking about that, including any potential termination fees we should be thinking about this quarter?

[John Cromling, executive]

Well, we know the rig rates will go with the activity level. And if the rig count and the land rig fleet overall continues to decline, the day rates will go down. What we saw in the first quarter were not significant decreases, but there are decreases on a spot market. So that will continue until we see the overall rig activity increase. It just no way around it.

[Operator]

Our next question comes from John Wong from RBC.

[John Wong, analyst]

You mentioned earlier in the call that -- you referred to your longer-term outstanding debt. The 6 and 5a to 21 has just stepped down to par this past month at the par call. Given the relative favorable market conditions, have there been any discussions about potentially opportunistically extending out their final maturity?

[Larry Pinkston, executive]

Well, of course, we're starting to look at it. And we'll be in a position that market -- when the market opens up to where we think it's timing. I think it's prudent for us to go and get something done. It's certainly not any emergency, but it's more of a market timing issue. But yes, we need to get them extended out here sometime.

[John Wong, analyst]

Okay. Is there -- like if there are any partake are you waiting on a potential target as far as funding rate on that? Or like what would catalyze a movement from your guys' side?

[Larry Pinkston, executive]

Well. The thing we're watching for right now with our advisors are continuing to reminding us. The energy market for financing really hasn't opened up much. I mean, there has been one or two. The broader market has been pretty wide open, but we're waiting for the energy side of the bond market to open up more -- toward this more activity and investors are ready to get back into the energy side. But right now, that's kind of what we're waiting on this for that segment of the financing to open up.

[Operator]

[Operator Instructions] And our next question comes from Craig Gilbert from Linden Advisors.

[Craig Gilbert, analyst]

Can you talk about your free cash flow expectations for the remainder of the year? And I guess, any update on your capital spending? And similarly, along with that, you mentioned potentially purchasing assets, additional acreage. How you plan to fund that? Is that something that you would fund with additional draws on the revolver?

[Larry Pinkston, executive]

Well, we set our budget each year basically at the end of the previous year or earlier on in the year. We established what our budget was at the beginning of this year. We'll review that again in midyear. But our budget is always what we expect -- what we anticipate our cash flow to be. So we don't anticipate using -- from beginning of the year to the end of the year, we don't anticipate depending any outstandings on our revolver. Now during the year, maybe some outstanding because of the timing of our drilling operations. But year-to-year, we're not -- we don't plan on any increases on our revolver. Anything that we buy acreage-wise, lease acreage-wise or just our drilling operation will all be within our budget. Any kind of acquisitions of producing properties or more larger acquisitions of course wouldn't be under our budget immediately. We would have to use the line for that. But nothing other than acquisitions would be used the line for. If that acquisition was large enough and we were comfortable with the amount of borrowings, we'd slowdown in our drilling operations and pay down -- pay the line back down. So we don't go into the year anticipating borrowings under our line. Again, on a year-end to year-end basis. During the year, yes, it could work out that way, but it's not over the 12-month period.

[Craig Gilbert, analyst]

So does that mean that we should -- I'm sorry.

[Larry Pinkston, executive]

Well, I mean, I was just going to follow up with your questions about free cash flow. We don't -- we used all of our available cash flow that we have on our budget each year. We will grow -- hopefully, grow our reserves -- oil and gas reserves this year. We've already added 2 new drilling rigs into our fleet this year. So there's a certain amount of growth that's factored into the -- our capital expenditures, but we made -- I hope that answers the free cash flow number. We plan on reinvesting our overall cash flow into the growth of the company.

[Craig Gilbert, analyst]

Does -- is the free -- spending to free cash flow, does that include interest expenses? Or is that mainly just CapEx?

[Larry Pinkston, executive]

No, that's everything. Again, it kind of comes back to debt. We don't expect any debt. We expect to end the year with the same amount of debt we had at the beginning of the year. So that covers everything, interest, G&A. I hope you are getting comfortable with it.

[Craig Gilbert, analyst]

Okay. So we should expect to see the $40 million drawn repaid throughout the year?

[Larry Pinkston, executive]

Yes.

[Operator]

And we are showing no further questions. I will now turn the call back to Larry Pinkston for closing comments.

[Larry Pinkston, executive]

Thank you for joining us this morning. And we appreciate your questions. They were all good questions, and we hope to see many of you in the next few months as we travel around. Thanks, again.

[Operator]

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating, and you may now disconnect.