Unit Corporation (NYSE:UNT) Q3 2017 Earnings Conference Call November 2, 2017 11:00 AM ET
Larry Pinkston – President and Chief Executive Officer
David Merrill - Senior Vice President, Chief Financial Officer and Treasurer
Frank Young - Senior Vice President-Exploration and Production-Unit Petroleum Company
John Cromling – Executive Vice President-Drilling Company
Bob Parks – Manager and President-Superior Pipeline Company
Neal Dingmann - Sun Trust
Marshall Adkins – Raymond James
Charles Robertson – Cowen
Welcome to the Unit Corporation’s Third Quarter 2017 Earnings Call. My name is Jennet, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. 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 will 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, President and CEO. Mr. Pinkston, you may begin.
Thank you, Jeanette. Good morning everyone. We want to thank you for joining us this morning. With me today are David Merrill, Frank Young, John Cromling and Bob Parks. Each of these gentlemen will be providing you with updates concerning their segments in a few moments. After their comments are concluded, we will take questions.
Before I turn the call over for the business segment discussions, I would like to offer just a few remarks. While we continue to maintain an optimistic outlook for commodity prices, we are also very aware that prices can fluctuate and will fluctuate significantly. Therefore, we must be prepared to respond accordingly. At the outside of each year, we endeavor to establish a capital expenditure budget that is inline with our anticipated cash flow for the year excluding acquisitions.
Our 2017 capital expenditures plan, which was adjusted modestly upward at mid year, has positioned the company to execute our plan while remaining within cash flow. This is not a new focus, but rather one that it enables our company to maintain a strong physical position during this in prior adverse cycles. We’re now in the preliminary stages of planning our 2018 capital expenditure budget, which we will release during the fourth quarter earnings call.
Our oil and natural gas segment experienced sequential quarterly production growth despite the effect of hurricane Harvey as noted in our press release. We continue to see some very encouraging well results in our core plays and believe that we are positioned with an ample opportunity economic well prospect to provide growth for many years to come. Our contract drilling segment has performed inline with the industry as we saw utilization grow rapidly through the first two quarters and back-off slightly late in the third quarter as frustrating as it may be to give up any grant no matter how temporary we continue to have discussions with operators’ interest in adding rig at the beginning of 2018.
For our midstream segment, although we continue to operate largely in ethane rejection mode, we have seen processing volumes increased at our Cashion and Hemphill facilities, which has allowed us to grow both processed volumes and liquids sold volumes. Further improvement in natural gas liquid process can have a very positive effect on this segment of our business.
As you’re all aware, David Merrill was recently promoted as Chief Operating Officer of Unit Corporation. In the interim, we have retained his CFO role until a replacement can be made. The process is currently underway. David has been a tremendous asset to Unit for 13 years and we look forward for his contribution in his new role.
I now would like to turn the call over to David.
Thank you, Larry, and good morning to everyone. We’ve reported net income for the third quarter of $3.7 million, or $0.07 per diluted share. Adjusted net income for the quarter, which excludes the effect of non-cash derivatives, was $5.3 million, or $0.10 per diluted share. Our non-GAAP financial measures reconciliation has been included in our press release.
For the oil and natural gas segment, revenue for the third quarter increased 3% over the second quarter because of the increased production and higher oil and natural gas liquids prices. Production for the quarter was reduced by approximately 100,000 barrels of oil equivalent due to planned outages and delay attributable to hurricane Harvey. Operating costs for equivalent barrel for the third quarter decreased 2% from the second quarter primarily because of higher production volumes.
For the contract drilling segment, revenue for the third quarter increased 31% over the second quarter because of an increase in the number of drilling rigs operating and it increased an average day rate. Operating costs for the third quarter increased 28% over the second quarter primarily due to the more rigs operating.
For the midstream segment, revenue for the third quarter increased 7% over the second quarter primarily because of higher liquids prices an increased liquids and processed volume. Operating cost for the third quarter increased 6% over the second quarter because of increased gas purchase prices and volumes and higher field rate operating expenses.
We ended the third quarter of 2017 with total long-term debt of $803.8 million, a decrease of $2.3 million from the end of the second quarter. Long-term debt consists of $641.7 million of senior subordinated notes net of unamortized discount and debt issue costs and $162.1 million of borrowings under our credit agreement.
Our credit agreement borrowing base as determined by our lenders in the recently completed regularly scheduled redetermination remains unchanged at $475 million. The borrowing base consists of our oil and gas properties and the midstream business does not our fleet of drilling rigs. Our senior leverage ratio was 0.53 times EBITDA at the end of the third quarter and the maximum senior leverage covenant has been no greater than 2.75 times EBITDA.
Our anticipated operating segment capital expenditures excluding acquisition are $273 million, which is within our anticipated cash flows and proceeds from non-core asset sales. While we have not completed our 2018 budget process, we anticipate our 2018 capital expenditures will be within anticipated cash flows and proceeds from non-core asset sales.
At this time, I will turn the call over to Frank for the oil and natural gas segment update.
Good morning. Today, I will give you an operational update on our Wilcox, Granite Wash and Hoxbar plays as well as provide more guidance about what we hope to expect in 2018 from our STACK play. During the quarter, Unit grew production by over 5% that despite operations may negatively impacted by hurricane Harvey.
Total production for the quarter was $4.1 million boe compared to production of 3.9 million boe during the second quarter of 2017. Liquids production represented 46% of our total equivalent production for the third quarter. Production is expected to have another sequential increase in the fourth quarter resulting in total production for 2017 of approximately 16 million boe.
During the quarter, plant outages and delays attributable to hurricane Harvey reduced production by approximately 100,000 barrel of oil equivalent. The effects of Harvey were principally due to NGL bottlenecks from fractionation plant partial shut-downs and operational delays on new wells and recompletions.
After the end of the quarter, the third-party processing plant for the majority of Unit's natural gas production in the Gulf Coast area went down due to equipment failure. The plant was down seven days before operations to be resumed. Cumulatively, hurricane Harvey, the Texas Panhandle ice storm in the first quarter, and third-party plant downtimes will reduce production for the year by approximately 460,000 barrels of oil equivalent. Without these disruptions, production for 2017 would have been at the high end of our previous guidance of 16 million to 16.5 million boe.
In the Wilcox area in South Texas, we continued our strategy of developing high reward low risk recompletion and infill drilling in the Gilly Field area and presenting our twin growth initiatives of building our horizontal drilling inventory and drilling exploration wells to test new Wilcox prospects.
Today, during 2017, Unit has spent approximately $7.8 million executing 29 recompletions and workovers, which has increased production 3,000 boe per day or 350%. In addition, two higher rate of return infill wells have been drilled and completed in the Gilly Field area and a third village mill horizontal well has been drilled and recently fracs were stimulated.
At our Cherry Creek exploration prospect, we are close to having pipeline and surface facilities installed for the Trinity number one to being first production, which we expect in late November or early December. We plan to drill a second well late this year or early next year to help further delineate the Cherry Creek prospect. We recently started a well – we also recently started a well – the second well in the Cherry Creek prospect should provide more data about the potential side of the field.
In addition to the Cherry Creek prospect, we recently started a well on our brand exploration prospect. As a result of these operations, production from this area continues to increase with year-over-year third quarter production growing 2% despite the negative impact of hurricane Harvey and the exit rate at year-end 2017 anticipated to be 15% to 20% higher compared to the exit rate at year-end 2016.
In the Granite Wash play, we continued the extended lateral drilling program in our Buffalo Wallow field. We plan to continue this drilling program throughout 2017 and for the foreseeable future, during the quarter two wells had first production both in the C1 interval and we have been pleased with the results. Two additional wells were drilled during the quarter and were recently fracture stimulated using the zipper frac technique, one in the A2 interval and one in the B interval, which is our first extended lateral B interval test.
Also during the third quarter, we spud our first two wells, anticipated to have 9,500 foot laterals in Buffalo Wallow field. The first of these wells have been successfully drilled and is awaiting completion while we finished drilling the second. Production rates from the extended lateral well program today are meeting expectations and at a projected well cost of $6.4 million have a higher rate of return especially when including the gas gathering and processing margins realized by Superior Unit’s midstream company that gathers and processes all the gas produced from Buffalo Wallow field.
In the Southern Oklahoma Hoxbar Oil Trend area, or SOHOT, we continued our drilling program in response to the Oklahoma state legislature bill passed and signed into law in June of 2017, which allowed extended lateral drilling across the state beginning in late August of 2017. We have been reworking our rig schedule to incorporate longer lateral horizontal wells. We believe longer horizontals will lead to further improve well economics in both the Marchand and Medrano sands. We plan to spud our first extended lateral Marchand sand wells in November, this month.
In the STACK play, we are focused on blocking up our acreage position and preparing for a 2018 drilling program. We have participated in 27 non-operated STACK wells today and the well test information continues to provide encouraging results near our operated acreage positions. We anticipate our drilling program will be comprised mostly of wells with either 7,500 foot laterals or 10,000 foot laterals depending on which lateral length accommodates our acreage position the best.
On the land side, our plans are to have 4,000 to 5,000 net acres over the next year to block up and add to our current 15,000 acre position. As more well test information that comes available and we add acreage and get more clarity around our development plan. We will periodically update our anticipated operated and non-operated well count.
Currently, we see 100 to 200 operated wells on our inventory with the major uncertainty being well density. We anticipate Unit’s working interest in the majority of STACK operated wells to fall within 30% to 60% range. On the non-operated side, we see a 400 to 900 well inventory with the major uncertainty again being well density. We anticipate Unit’s working interest in the majority of spec non-operated wells to be less than 15%.
In addition to well density uncertainly, there is still some uncertainty around what commodity prices will be necessary for each location to be economic. In summary, I'm pleased with the quarter-over-quarter growth we are seeing from our core plays, while keeping our capital spending near cash flow. Our ability to move the longer laterals in the Granite Wash, SOHOT and STACK will improve the efficiency with which we convert capital into production and production into cash flow for reinvestment.
With the STACK play added into the mix, our low risk development drilling inventory is large enough to provide production and reserve growth for several years to come. In addition, our exploration prospects, especially in the Gulf Coast area have homerun top reserve potential as illustrated by our Gilly Field discovery.
Unit Petroleum strategy have been a low cost operator and being disciplined in terms of focusing in play areas where we can keep our land acquisition cost low relative to industry is sustainable and one that can deliver profitable growth over the long-term.
At this time, I will now turn the call over to John for the Drilling Company update.
Thank you, Frank, and good morning everyone. The third quarter was very positive for the contract drilling segment even though our rig utilization fluctuated slightly during the quarter, our daily operating costs continue to decrease and cash flow margins has steadily improved.
The average day rate for the third quarter was $16,454, an increase of $492 per day over the second quarter. The average total daily revenue before intercompany eliminations was $16,834, an increase of $240 over the second quarter. The day rate increase was a result of incremental rate increases on several rigs, primarily due to a wage increase initiated in the third quarter in the mid-con region.
Our total daily operating costs before intercompany eliminations decreased by $534 for the third quarter as compared to the second while absorbing the labor increase on many of the operating rigs. The decrease was due primarily to fewer STACK rigs being put into service and the cost directly related to reactivating STACK rigs and the operating rigs performing more efficiently.
We did however experienced additional cost of reactivating three rigs during the quarter plus the cost of moving one rig from one basin to another. The average per day operating margin for the third quarter before elimination of intercompany profits was $5,495, which is $774 per day increase over the second quarter. Our non-GAAP reconciliation can be found in today's press release.
We began the quarter with 33 operating rigs and increased to 36 during the quarter and then dropped back to 33 by quarter's end. Presently, we have 33 operating rigs. Our activity level has remained relatively consistent with industry activity level. Currently, all ten of our BOSS rigs are operating with six of them under term contracts. During the last year, we have put into service two new BOSS rigs, 20 1,500 horsepower SCR rigs and one 1,000 horsepower SCR rig. All of these 21 rigs do not require any upgrades or additional equipment. The other nine rigs were upgraded to varying degrees with walking systems, 7,500 psi mud systems, dirt pumps and/or hydraulic catwalks.
Three of these rigs were put into service during the third quarter. However, we were able to reduce our daily cost substantially and increase our daily cash flow margins. The land rig utilization rate has been declining during the past month while the industry aggregated also. However, we are optimistic that current demand for rigs will be sustainable for the near-term. The enquires for rigs for the beginning of 2018 has increased and it appears that the recent reduction in rig count is due to budget constraints for 2017 leading us to believe that the rig count will rebound during the first quarter of 2018.
At this time, I will turn the call over to Bob for the Superior Pipeline update.
Thank you, John. The midstream segment completed a successful third quarter producing consistent financial results and favorable outcomes at many of our key facilities. Our segment operating profit before depreciation for the first nine months of 2017 increased to $38.6 million, which represents a 15% increase over the first nine months of 2016. This result is primarily achieved due to monitoring and controlling operating expenses as well as receiving better pricing for oil, gas and liquids.
For the third quarter total throughput volume remains constant consistent at approximately 384 million cubic feet per day as compared to the second quarter of 2017 while gas process volume increased to 140 million cubic feet per day, which represents a 4% increase from the second quarter of 2017. This increase is mainly due to higher volume at our Hemphill and Cashion facility.
If the mortgage prices continue to improve, which is the higher gross margins at our processing facilities. We invented approximately $4.8 million in capital projects in the third quarter of 2017 for a year-to-date total of $10.1 million. For 2017, our estimated capital expenditures are approximately $18.9 million. I’ll now focus on several comparable key midstream assets.
Starting with our Haynesville facilities located in the Granite Wash area in the Texas Panhandle, in the third quarter our average total throughput volume increased approximately 60.8 million cubic feet per day and production of natural gas liquids increased to approximately 164,000 gallons per day. While the process volume and NGL volume increased this quarter due to additional volume received from the Buffalo Wallow area.
During the third quarter, we connected two new wells from the Buffalo Wallow area, which brings our total well connected to four for the year. We expect drilling activities continue in this area and we are in the process of connecting two additional wells by the end of the year. Moving to our Pittsburgh Mills gathering facility located in Pennsylvania, this system continues to achieve solid financial result.
Our total throughput volume for the third quarter averaged approximately 128.5 million cubic feet per day after connecting the Allen well pad in May of 2017, which includes five new wells. We now have a total of 12 well pads connected to our Pittsburgh Mills gathering system with a total of 55 producing wells. Our next well pad scheduled to be connected is the Miller pad, which will be located on the south end of our system.
We are continuing preliminary construction activities with latest connecting this pad and expect to start pipeline construction after the first of the year. The Miller pad going through seven new wells and we expect first flow in the third quarter of 2018. Additionally, we have received notice that seven new infill wells will be drilled on existing well pads. We expect these wells to be connected and flowing in the second half of 2018.
At our Cashion processing facility located in central Oklahoma, our average throughput volume increased approximately 38.4 million cubic feet per day. We have connected four new wells in the third quarter and are in the process of expanding the gas and gathering systems to connect Cashion from the new producer. We have connected the first three wells in this producer and we are in the process of constructing the pipeline extension to connect additional wells.
Additionally, our five year contract with another third-party producer which is effective on January 1, 2017 [indiscernible] together and process 10 million cubic feet per day at our Cashion facility. This is a fee based contract that includes a shortfall provision that applies that the gap is not delivered and any shortfall amount will be sold annually.
In summary, total throughput volumes have remained relatively stable for our process volume and liquids sold volumes had modest increases over the last quarter. We continue to connect new wells; our Hemphill and Cashion processing facilities while our fee based Appalachian systems continue to deliver solid financial results. We have seen some benefits this quarter from improved prices on our processing facilities and we are in a position to take advantage of any future price improvement.
As producer activity levels continues to increase and with our available processing and gathering capacity, we anticipate completing 2017 with strong financial results and we feel the midstream segment is well positioned going into 2018.
At this time, I will turn the call back over to Larry.
Thank you, Bob. And before we move on the Q&A, I would like to just point out a few things. We’re very pleased to complete another quarter with very positive improvements in each of our three segments. Well all have continue to maintain our focus on deepening capital expenditures in line with expected cash flow. This has enabled us to maintain a strong position while we continue our growth process.
In our exploration and production segment, we are very pleased to have increased quarter production despite operations being impacted by hurricane Harvey. We are pleased with the long-term growth outlook for this segment. The large low risk development inventory from our STACK position combined with the production outlook from our other three core areas should give us a very favorable results going forward.
Our contract drilling segment continues to perform very well in today’s market. Our activity level remains relatively consistent with industry activity levels. Our focus for this segment is to anticipate and meet our customer needs, which we've have done a very remarkable job of achieving. All 10 BOSS rigs are currently operating and we have 23 SCR rigs in operation. I am proud of what our drilling team has been able to accomplish during these very challenging times.
Our midstream segment has positioned well to take advantage of opportunities that may arise. We continue to see new opportunities to grow this business segment, any increases in liquid pricing would only further improve our processing and liquids sold volumes just as we've seen this quarter. All in all it’s a good quarter for us and we will continue to maintain our physically conservative approach.
I would like to now turn the call over to questions. Jeanette?
Yes, thank you. And we will now begin the question-and-answer session. [Operator Instructions] and our first question comes from Neal Dingmann of Sun Trust. Please go ahead.
Good morning guys. Nice details laid out. I think my first question may be for John in your area. John, I'm wondering for you or Larry, I guess if the rig activity looks like now it’s kind of stabilized a little bit. Does that mean that bidding activity too has slowed down or if you could just talk about that, number one on the rig side.
Neal, yes, it did slowed down a couple of weeks ago, but may be in the last well probably about four weeks ago, or during the last two weeks, it’s increased a lot not for jobs to happen next week or this month, but for mid-December, and most especially the first quarter of 2018. So not only have the enquiries increased, but we have several pending contracts for rigs that we’ll work in the first quarter of 2018. Now these are not additional rigs, what we have. We have been operating. But that would be just a continuation of jobs that we have going, plus those two to three that went down in the letter part of this quarter.
Okay, and one follow-up on the rig side. You yielded fantastic it looks like on margins, had a very nice increase on the third quarter sequentially maybe just address that, is that something that when we look this current quarter in 2018, can we continue maybe not at that level but at least, continue with the margin increase as we saw in the 3Q?
Yes we think so. And the reason that those costs went down so much in the third quarter. We had won, we had more rigs days, so all the I/Os are affective by rig days, indirect cost, large and auto expense, G&A, those things come down on a per day basis because we have more weekdays to divide by. But we also had less expansion in this quarter for reactivating stacked rigs, even though we bought three more out during this quarter. So it's just an overall pre-equation that, it just takes time if we start ramping up the beginning of the year at the speed that the industry did and that's included.
And now things are more stable. And so I think the results are relatively to be expected going forward.
Okay, and then one last moving over to the upstream side maybe for Frank. Frank just looking at the Wilcox, it seem like between Cherry Creek hill and dodge mill, you guys were pretty active in all three. Is that – will that continue to be the case? And I know you’ll have the full 2018 plan. But I’m just wondering if that will be a focus, and when you look at Wilcox for next year. Will you target any one area or you will be kind of similar planned this year?
It will be a little bit next year because we plan on drilling some delineation wells to our exploration prospects, so we will continue with the recompletion and work-over programs in 2018 in the Gilly area. We will also drills some development wells around that area. But we will have – and also in dodge mills but then we'll have some probably a little bit more exploration dollars spent on drilling in 2018 than we did in 2017. We do plan to – our plan is still to run a rig for all of 2018, will be our recommendation to the Board to run a rig for all of 2018 in the Wilcox area.
Very good. Thank you. I’ll hop back in queue.
Thank you. And our next question comes from – one moment Marshall Adkins of Raymond James. Please go ahead.
Good morning guys. Frank I’m going to start with you. You're going to come in at 16 mm boe this year, any initial thoughts where next year might end up, I know it's early and it depends on pricing and whatnot. But any just kind of directional thoughts there?
No, we’ve seen good, sequential quarter-over-quarter growth this year. And I think in the script I said, we would expect another sequential growth in the fourth quarter. We haven't done our 2018 budget yet. Our anticipation is that we would see – we will see growth in 2018 and during our budget process, we'll see it we're going to be able to achieve sequential quarter-over-quarter growth. But we'll see annual growth for sure. Whether we can grow production every single quarter, it just remains to be the same target a chance to really dig into the budget details.
Okay, well speaking into that budget – go ahead.
Alright, sorry, I did not have anything else.
Okay. If you look at all the different areas that are going to be attracting E&P capital. You got the Granite Wash, the stack kind of seems to be coming up and several others. Where – give me a rough breakdown of where you see most of the capital going? Or is it going to be evenly spread between now – now seems like have five kind of key areas.
The capital spending is going to be spread between our areas. Rig counts will be spread between our areas. Now some areas that will have a higher working interest than others, so you'll see some very variations in net cap – net capital between areas, but we – what we would perceive is continuing our rig in the Granite Wash, continuing the SOHOT rig, continuing the Wilcox rig and then adding a STACK rig. That's where we're headed for 2018 in terms of putting our budget recommendation together.
Okay, all right, good, that's helpful. Then let me just shift back over to the drilling rig side. John, it seems like demand for SCR rigs is holding up remarkably well as long as they're outfitted with 7,500 psi and all the pumps and bells and whistles. Is that accurate? And how long do you think that stickiness, if you will for SCR rigs lasts?
Yes, I think you’re correct in that, Marshall. And I think it will continue and the reason that I think that that situation just right now, a lot of the stacked AC rigs, they’re AC rigs, but they're no more equipped than our SCR rigs. So I don't think it's as much a question of AC versus DC if they're equipped properly. Its question of what kind of pumps, no what kind, but what sized pumps, pressure rating of the mud-system, all the other things, the drilling programs that you can run with those kind of rigs. So I think we can remain very competitive with the SCR rigs.
And as you know, our goal is still to continue our BOSS rig program and add to that as the opportunity arises, so we're just trying to put both of those parts together to make it work.
And your BOSS rigs, correct me if I'm wrong, well, they're getting meaningfully better margins than the SCR rigs at this stage, correct.
In some cases, there are exceptions to both sides of that statement. [Indiscernible] win contracts were began as of the big play in it, but overall, yes, that's true.
Are you considering upgrading your SCR to AC?
No, not really because if we still think that as we go with the AC rigs to BOSS rig, will be our preference. And we think we can do other upgrades on SCR rigs that will obtain the same results.
Okay, all right. Last one for me, it does seem as you mentioned earlier, great margin expansion. It looks like two thirds of it was kind of on the revenue side, which you assume is mainly pricing, but better utilization helps. How much pressure you're getting on labor cost? I mean we keep hearing about that from everyone across the industry. And I guess it little inspires that you did that well on margins given what I’ve been hearing about labor. So just comment real quickly on any pressure that you might see there?
We had a – we experienced that pressure. And first of all, just we increased the wages for all the crews in mid-continent region. So, yes, that pressure is there, but we have had not any significant problems in manning our rigs as we've added additional rigs, but there's always will be a pressure with continued growth. But the lessening of the rig count by 30, 34 rigs in the last month has alleviated part of that issue.
All right, okay guys. Thank you all.
Thanks a lot.
Thank you. And our next question comes from Charles Robertson of Cowen. Please go ahead.
All right, switching back over to the upstream side. Little more color if you could provide, in the Wilcox on the exploratory targets and sort of what's your seeing there that you like?
So the Cherry Creek prospect is six miles from Gilly field, if you'll recall Gilly Field is a 500 Bcfe discovery and the cherry Creek prospect was drilled to test and find similar zones that are in the Gilly Field discovery. Cherry Creek, the first well we drilled at Trinity. I didn't mentioned that this quarter, but last quarter I think I’ve mentioned that the we tested that well at rates – at rates, but we’re very encouraging and we think that when that well comes on, it's going to come on high rates and high pressures and we'll just have to watch it for a couple of months to kind of see how the pressure declines, how the rates held up.
And in the meantime, our 3D seismic indicates the size of that field as significant and we will be drilling delineation well to go further up on structure and to prude up more of the size of the field. And that that delineation well, the Trinity number two will be drilled sometime in December or the first part of the first quarter of 2018. In addition, we have spud and are nearing the completion of prospect that we call brand prospect that that well – the exploration all there is called the angle. And the angle is nearing total depth and we're excited about that prospect.
It's an area where there has been some offsets production far from our exploration well and should we find what we hope to find our exploration well that could prove to be a very nice horizontal drilling area for us. And then beyond those two prospects, we have another large prospect that we plan on drilling and testing in the third quarter or four quarter of 2018 that is very near Gilly Field. So that's about as much color as I can give at this point, Charles.
Defiantly a lot more color than I was expecting. Thanks.
Oh, there you go. It’s good. In the STACK, what are your thoughts there? What area will you be targeting the normal or the over pressured area first? Any thoughts to that?
Most of our acreage is in the over pressured window, which is fortunate because the over pressured window continues to produce best well results in that play. We are very excited about the well results that we continue to see near our acreage position and wells that we're participating in. We haven't seen anything that will be discouraging to us in terms of being able to have a very successful drilling program there. In 2018, we would like to drill wells and all of our wells that we will drill in 2018 will be in the over pressured window. And some of the drilling will likely be in the western STACK extension and some will be more into the main part of STACK.
All right, thank you very much.
Thank you [Operator Instructions] And I'm showing no questions at this time.
Thank you, Jeanette. We like to just thank everybody again for joining us this morning and look forward to seeing many of you as we can over the next couple of months in our trip around visitings. Again, thank you again and that concludes our call.
Thank you, and thank you ladies and gentlemen. This concludes today's conference. Thank you for participating and you may now disconnect.