UNT
#Thank you, Jeanette.
Good morning, everyone.
We want to thank you for joining us this morning.
With me today are <UNK> <UNK>, <UNK> <UNK>, <UNK> <UNK> and Bob <UNK>.
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'd like to offer just a few remarks.
While we continue to maintain an optimistic outlook for commodity prices, we also very aware that prices can fluctuate and will fluctuate significantly.
Therefore, we must be prepared to respond accordingly.
At the outset of each year, we endeavor to establish a capital expenditure budget that is in line with our anticipated cash flow for the year, excluding acquisitions.
Our 2017 capital expenditures plan, which was adjusted modestly upward at midyear, has positioned the company to execute our plan for remaining within cash flow.
This is not a new focus but rather one that has enabled our company to maintain a strong physical position during this and 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 segments 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 reserves ---+ well results in our core plays and believe that we are positioned with an ample opportunity in economic well prospects to provide growth for many years to come.
Our contract drilling segment has performed in line 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 ground no matter how temporary, we continue to have discussions with operators interested in adding rigs at the beginning of 2018.
For our midstream segment, although we continue to operate largely in ethane rejection mode, we have seen processing volumes increase at our Cashion and Hemphill facilities, which has allowed us to grow both processed volumes and liquids sold volumes.
Further improvement in natural gas liquids process can have a very positive effect on this segment of our business.
As you are all aware, <UNK> <UNK> was recently promoted to Chief Operating Officer in Unit Corporation.
In the interim, he has retained his CFO role until a replacement can be made.
The process is currently underway.
<UNK> has been a tremendous asset to Unit for 13 years and we look forward this contribution in his new role.
I now would like to turn the call over to <UNK>.
Good morning.
Today I'll review the 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%, despite operations being 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 barrels of oil equivalent.
The effects of Harvey were principally due to NGL bottlenecks from fractionation plant partial shutdowns, and operational delays on new wells and re-completions.
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 7 days before operations could be resumed.
Cumulatively, Hurricane Harvey, the Texas Panhandle eye storm in the first quarter and third-party plant downtimes will reduce production for the year by approximately 460 million ---+ 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 re-completions and infill drilling in the Gilly field area and pursuing our twin growth initiatives of building our horizontal growing inventory and drilling exploration wells to test new Wilcox prospects.
Today, during 2017, Unit has spent approximately $7.8 million, executing 29 re-completions and workovers, which has increased production 3000 BOE per day or 350%.
In addition, 2 higher rate of return infill wells have been drilled and completed in the Gilly field area and a third Village Mills horizontal well has been drilled and recently fracture stimulated.
At our Cherry Creek exploration prospect, we are close to having pipeline and surface facility installed for the Trinity #1 to begin 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, excuse me ---+ the second well in the Cherry Creek prospect should provide more data about the potential size of the field.
In addition to the Cherry Creek prospect, we recently started a well in our Brant 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 continue to extend the 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, 2 wells had first production, both in the C-1 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, 1 in the A-2 interval and 1 in the B-interval, which is our first extended lateral B-interval test.
Also, during the third quarter, we spud our first 2 wells anticipated to have 9,500-foot laterals in the Buffalo Wallow field.
The first of these wells has been successfully drilled and is awaiting completion, while we finish drilling the second.
Production rates from the extended lateral well program to date are meeting expectations and at a projected well cost ---+ excuse me ---+ of $6.4 million have a higher rate of return, especially when including the Gas gathering and processing margins realized by Superior in its 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 in law in June 2017, which allowed extended lateral drilling across the state beginning in late August '17.
We have been reworking our rigs schedule to incorporate longer lateral horizontal wells.
We believe longer horizontals will lead to further improve well economics in both Marchand and Medrano sands.
We plan to spud our first extended lateral and sand wells in November ---+ this month.
In the STACK play, we are focused on blocking up our acreage position in preparing for a 2018 drilling program.
We have participated in 27 non-operated STACK wells to date 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 add 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 becomes 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 in 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- and 900 well-inventory with the major uncertainty again being well density.
We anticipate Unit's working interest in the majority of STACK non-operated wells to be less than 15%.
In addition to well density uncertainty, there is still some uncertainty around what commodity prices will be necessary for each location of the economic.
In summary, I'm pleased with the quarter-over-quarter growth we're 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 in 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 home-run type reserve potential as illustrated by our Gilly field discovery.
Unit Petroleum's strategy of being 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 <UNK> for the drilling company update.
Thank you, <UNK>, 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 cost continue to decrease and cash flow margins have 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 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 stacked rigs and the operating rigs performing more efficiently.
We did, however, experience additional costs of reactivating 3 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 a $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 the industry activity level.
Currently, all 10 of our BOSS rigs are operating with 6 of them under term contracts.
During the last year, we have put into service 2 new BOSS rigs, 20 1,500-horsepower SCR rigs, and 1 1,000-horsepower SCR rig.
Twelve of these 21 rigs did not require any upgrades or additional equipment.
The other 9 rigs were upgraded to varying degrees with walking systems, 7,500 PSI mud systems, [dirt] pumps and/or hydraulic catwalks.
3 of these rigs were put into service during the third quarter.
However, we were able to reduce our daily costs substantially and increase our daily cash flow margin.
The land rig utilization rate has been declining during the past month for the industry and for Unit also.
However, we are optimistic that the current demand for rigs will be sustainable for the near term.
The inquiries 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 rig count will rebound during the first quarter of 2018.
At this time, I'll turn the call over to Bob for the Superior Pipeline update.
Thank you, <UNK>.
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 9 months of 2017 increased to $38.6 million, which represents a 15% increase over the first 9 months of 2016.
This result is primarily achieved due to monitoring and controlling operating expenses as well as receiving better prices for oil, gas and liquids.
For the third quarter, total throughput volume remained constant, consistent at approximately 384 million cubic feet per day as compared to the second quarter 2017 while gas processed volume increase 140 million cubic feet per day, which represents 4% increase from the second quarter 2017.
This increased mainly due to higher volumes at our hands-on cash facility.
If commodity prices continue to improve, we should see higher gross margins at our profit facilities.
We invested 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 dollars.
I'll now focus on several key midstream assets.
Starting with our Hemphill facility located in the Granite Wash area in the Texas Panhandle, in the third quarter our average total throughput volume increased to approximately $60.8 million cubic feet per day and production of natural gas liquids increased to approximately 164,000 gallons per day.
Most process volumes and NGL volume increased this quarter due to additional volume received in the Buffalo Wallow area.
During the third quarter, we connected 2 new well from the Buffalo Wallow area, which brings our total well connects to 4 for the year.
We expect drilling activities to continue in this area and we're in the process of connecting 2 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 results.
Our total throughput volume for the third quarter averaged approximately at 128.5 million cubic feet per day after connecting Allen well pad in May 2017, which included 5 new wells, we now have a total of 12 well pads connected for 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 we located on the south end of our system.
We are continuing preliminary construction activities with [pledge] connecting this pad and expect to start pipeline construction after the first of the year.
The Miller pad will include 7 new wells and we expect first flow in the third quarter 2018.
Additionally, we received notice that 7 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 to approximately 38.4 million cubic feet per day.
We connected 4 new wells in the third quarter and are in the process of expanding the Cashion gathering system to connect production from a new producer.
We've connected the first 3 wells from the producer and we are in the process of constructing the pipeline extensions to connect additional wells.
Additionally, our 5-year contract with another third-party producer, which was effective on January 1, 2017, will allow us to gather and process 10 million cubic per day at our Cashion facility.
This is a fee-based contract that includes a shortfall provision that applies if the gas is not delivered and any shortfall amount will be sold annually.
In summary, total throughput volumes have remained relatively stable for our process volumes, electric volumes, sold volumes had modest increases over last quarter.
We continue to connect new wells at our Hemphill and Cashion processing facility while our fee-based Appalachian systems continue to deliver solid financial results.
We have seen some benefits this quarter from improved prices at our processing facility.
And we are positioned to take advantage of any future price improvements.
As producer activity levels continue to increase, and with our available processing and gathering capacity, we anticipate complete 2017 with strong financial results and we feel the midstream segment is well positioned going into 2018.
At this time, I'll turn the call back over to <UNK>.
Thank you, Bob.
Before we move on to the Q&A, I'd like to just point out a few things.
We're very pleased to complete another quarter with some very positive improvements in each of our 3 segments, all while continue to maintain our focus on keeping capital expenditures in line with expected cash flow.
This has enabled us to maintain a strong business position while we continue our growth process.
In our expression and production segment, we're very pleased to have increased quarter production despite operations being impacted by impacted by Hurricane Harvey.
We're pleased with the long-term growth outlook for the segment, the large low-risk development inventory from our STACK position combined with the production outlook from our other 3 core areas should give us 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 have done a very remarkable job of achieving.
All 10 BOSS rigs are currently operating and we have 23 SCR rigs in operation.
And I'm proud of what our drilling team has been able to accomplish during these very challenging times.
Our midstream segment is positioned well to take advantage of opportunities that may arise.
We continue to seek new opportunities to grow this business segment.
Any increase from liquids processing will only further improve our processing in liquid sold volumes such as we've seen this quarter.
All in all, it was 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.
<UNK>, it did.
It did slow down a couple of weeks ago but in the last ---+ probably about 4 weeks ago.
But during the last 2 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 ---+ and not only have the inquiries increased but we have several pending contracts for rigs that will work in the first quarter of '18.
Now these are not additional rigs to what we have or have been operating.
But that would be just a continuation of jobs that we have going plus those 2 to 3 that went down in the latter part of this quarter.
Yes, we think so.
And the reason that those costs went down so much in the third quarter, we had ---+ one, we had more rigs days, so all the I/Os that are affected by rig days, indirect cost, yards and auto expense, G&A, those things come down on a per day basis because we have more rig days to divide by.
But we also had less expansion in this quarter for reactivating stacked rigs, even though we've brought 3 more out during this quarter.
So it's just an overall progression that it just takes time when you 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.
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 '18 and during our budget process, we'll see if 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 seen till I get a chance to really dig into the budget details.
I didn't have anything else.
The capital spending is going to be spread between our areas, rig counts will be spread between our areas.
Now some areas have a higher working interest than others, so you'll see some variations in net capital between areas.
But we ---+ what we would foresee 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.
Yes, I think you're correct in that, <UNK>.
And I think it will continue.
And the reason that I think that, that situation that exists right now, a lot of the STACK AC rigs, they are AC 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.
It's a question of whether ---+ what kind of pumps ---+ not what kind but what size pumps, the 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.
In some cases.
There are exceptions to both side of that statement.
All depending on when the contracts were began has a big play in it, but overall, yes, that's true.
No, not really, because if we still think that as we go with the AC rig, the BOSS rig would be our preference and we think we can do other upgrades on SCR rigs that will attain the same results.
We had a ---+ we experienced that pressure and in the 1st of August, we increased the wages for all the crews in the Mid-Continent region.
So yes, that pressure is there, but we have not had any significant problems in manning our rigs as we've added additional rigs.
But it'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.
So the Cherry Creek prospect is 6 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 fields discovery.
Cherry Creek, the first well we drilled the Trinity.
I didn't mention it this quarter, but last quarter I think I mentioned that the we tested that well at rates ---+ at rates that were 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 hold up and in the meantime, our 3D seismic indicates the size of that field is significant and we will be drilling a delineation well to the go further up on structure and to prove up more of the size of the field and that delineation well, the Trinity #2, will be drilled sometime in December or the first part of the first quarter of '18.
In addition, we have spud and are nearing the completion prospect that we call Brant prospect, that well that the exploration over there is called the Ingle.
And the Ingle is nearing total depth and we're excited about that prospect.
It's an area where there has been some offset production not far from our exploration well and should we find what we hope to find our exploration well, it could prove to be a very nice horizontal drilling area for us.
And then beyond those 2 prospects, we have another large prospect that we plan on drilling and testing in the third quarter or fourth quarter of 2018.
That is very near Gilly field.
So that's about as much color as I can give at this point, <UNK>.
Most of our acreage is in the overpressured window, which is fortunate because the overpressured window continues to produce the 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 would be discouraging to us in terms of being able to have a very successful drilling program there.
In '18, we would like to drill wells and all of our wells that we will drill in '18 will be in the overpressured 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.
Thank you, Jeanette.
We'd 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, so.
Again, thank you again and that concludes our call.
