Q2 2019 Earnings Call
Welcome to the unit Corporation second quarter 2019 earnings call. My name is Tony and I'll 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.
<unk> believes or similar forward looking statements.
The companys actual results could differ materially from the results anticipated or projected in any such forward looking statements.
Additional detailed information concerning.
Factors that could cause actual results to differ materially from the information given today is readily available in todays 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 all non-GAAP measures to GAAP measures can also be found in todays press release.
This document is available on the company's website.
When I turn the call over to Larry Pinkston.
<unk> CEO Mr. Pinkston, you may begin.
Like you did it.
Good morning, everyone. Thank you for joining us this morning.
With me today are David Merrill less all right, John Cromling and Bob or.
Pete who will be providing you with updates about their areas. The responsibility and then we will take questions at the end of the call commodity prices have been very volatile in the industry have seen a continued softening in the U.S. drilling activity that's companies like to so disciplined capital spending natural gas and natural gas liquid prices have deteriorated and differentials on natural gas and nuclear remain wider and western Oklahoma and the Texas Pelayo.
The market is showing indications that they're pretty cool should start to improve during the latter part of the year and after 2020. This new infrastructure is placed into service.
The second quarter was influenced by a number of different factors, which are things will go over in their comments.
Given the outlook for commodity prices for the remainder of the year, our plant oil and natural gas segment drilling activities over the years have been completed and all the drilling rig we were operating at about being a really.
As anticipated we increased borrowings under our bank facility to fund the early 2019.
Activity levels.
Capital spending now reduced we anticipate the borrowings will be substantially reduced by urea.
About where like I'll turn the call over to David Merrill.
Thank you Larry.
While we have seen some very impressive results in our oil focused play from both our Red Fork and sell our drilling efforts.
We are faced with very challenging commodity prices for both natural gas and natural gas liquids.
With our capital expenditure being at the low end of our earlier projections.
When coupled with the first quarter third party plant shut down impacting our Wilcox production.
Our production for the year and expect it to be 17 to 17.2 billion barrels of oil equivalent.
Production, increasing in the second half of the year.
The strong well results in our Red Fork and so hot plate resulted in a 6% increase in our oil production for the quarter over the first quarter.
And we continue to have success, adding to our leasehold position.
Yeah, the pen sands plays.
We added approximately 2100 that acres during the quarter at an average cost of less than 1000 per acre.
We continue to see the opportunity for adding to that position in a cost effective manner.
Our contract drilling segment maintained 100% of our boss rig.
Sleep on her contract since the start of our boss rig program.
Our forties boss rig is now being built under a long term contract.
Our midstream segment has seen throughput growth as a result of execution on organic growth opportunities.
We continue to look for additional expansion opportunities for the midstream business.
I'll now turn the call over the last Austin.
Thanks, David we reported a net loss attributable to unit for the second quarter of $8.5 million or 16 cents per diluted share.
Adjusted net loss attributable to unit for the quarter, which excludes the effect of non cash derivatives was $12.9 million or 24 cents per diluted share versus adjusted net income of $4.5 million or nine cents per diluted share for the first quarter of 2019.
The primary factors contributing to the decline included 26% lower hedge natural gas prices, 22% lower natural gas liquid prices.
And 9% lower rig utilization.
Our non-GAAP financial measures reconciliation is included in our press release.
For the oil and natural gas segment revenues for the second quarter decreased 10% from the first quarter because of the lower natural gas and NGL prices previously discussed.
Equivalent production was relatively unchanged compared to the first quarter.
Operating costs for the second quarter increased 11% over the first quarter, primarily due to increased lease operating expenses associated with initial production on new wells drilled.
For the contract drilling segment revenues for the second quarter decreased 16% from the first quarter due to 9% fewer rigs operating in the quarter, partially offset by increased day rates.
Operating costs for the second quarter were 7% lower compared to the first quarter of this year, primarily due to fewer rigs operating.
For the midstream segment revenues for the second quarter decreased 16% from the first quarter of this year, primarily due to decreased gas and gas liquids prices, partially offset by increased condensate prices and gas volumes gathered.
Operating costs for the second quarter decreased 17% from the first quarter of this year because of decreased purchase prices.
We ended the second quarter of 2019 with long term debt of $756.6 million.
Long term debt consists of $645.6 million in senior subordinated notes net of unamortized discounts and debt issuance costs.
$103.5 million outstanding on the unit Corporation revolving credit agreement and $7.5 million outstanding under the superior revolving credit agreement the latter being non recourse to unit Corporation.
Our unit Corporation credit agreement borrowing base remains unchanged at $425 million.
With a maturity date of October 2023.
And the superior credit facility is a $200 million facility with a maturity date of May 2023.
We continue to assess market conditions relative to refinancing our $650 million senior subordinated notes, which mature in May 2021.
Our net leverage ratio on unit Corporation indebtedness was 2.4 times at the end of the second quarter.
At this time I will turn the call over to Frank for our oil and natural gas segment update.
Good morning.
The second quarter was a mixed bag per unit petroleum.
On the downside continued weakness in real net realized natural gas and NGL crosses reduced cash flow.
And in response, we drop rigs to keep capital spending in check.
Entering the first quarter unit had six rigs running focused primarily on drilling oil wells.
By the end of July unit Petroleum had no rigs running.
With the shutdown of our drilling activity coupled with the first quarter 14 day shutdown of our Wilcox production.
We now estimate our production for 2015 at 17 to 17.2 million BOE we.
And our capital spending of $270 million.
Production during the second half of 2015 will increase over the first half of 2019.
Due to the number of wells brought online during the second and third quarters.
On the upside our focus on drilling oil wells to increase oil production by 6%.
Over the prior quarter and we expect our 2019 oil production will be approximately 13% higher Europe year over year, and approximately 20% of our commodity mix by the end of the year.
The increase in oil production as a result of some very strong well results from our red for horizontal play that all will discuss.
Operating costs were 1% higher through the first half of 2019 compared to the first half of 2018.
And 11% higher quarter over quarter.
The quarterly increase was due to the increased concentration of new wells brought online during the second quarter as compared to the first quarter.
Looking forward, we expect gas differentials in the Texas Panhandle in Western Oklahoma to improve over the next several months.
Nutrition airs midship topline in kitting or Morgan's Gulf Coast Express applaud both expected to be placed into service later this year.
She nears line will increase takeaway capacity out of Oklahoma, Bob by 1.4 Bcf per day.
While candor Morgan's lines will move two Bcf per day of Permian gas production straight to the Gulf Coast.
Rather than coming up to the Texas Panhandle as it is now.
Mid con the basis differentials to Nymex for 2020.
Our currently approximately 40 cents tied or compared to what we experienced in the second quarter.
Which would benefit our realized gas for us.
Any improvements to nominate gas for us is without even further to our realized gas for us.
During the second quarter, we accelerated drilling operations in western Oklahoma to take advantage of the better economics associated with the more oil prone nature of work Thomas Red Fork play in our Soho Marchand play.
Both located within our pin sands prospect area.
Overall results from our Soho Marchand drilling program over the last 18 months have been in line with our top per expectations.
Resulting in excellent rates of return on our drilling and completion capex spend in this play.
But what I want to focus on today is our Red Fork play, which lock the Marchand, we are the industry leader in.
Units initial red Fork well on the Thomasville, which came online in September of 2018.
Continues to perform exceptionally well.
On a gross basis, the well had an IP 30 of over 2000 Boe per day.
Has cumulative production of 440000, Billy of which 52% as oil, 22% as natural gas liquids and 26% as gas.
During the second quarter and into early July three new rent for horizontal wells were completed.
On the Winguard 15, 22 number two HX the casing failure. After fracking the 7500 foot lateral resulted in only 1500 foot or 20% of the lateral being successfully completed.
Even so the well had an IP 30 of 413 Boe per day.
Well the casing failure was disappointing we will likely we likely would have had an IP 30 of over 2000 Boe per day.
If 80% of the lateral wouldn't have been lost.
The next well the Winguard farms 20, 128 number one HX.
With Juno has a 94% working interest and was completed in early July .
With a lateral length of 7000 feet.
At the end of July the wells was producing 2800 Boe per day.
With 75% of that being oil.
The last well the Saratoga 17, 20 number one HX, which unit has a 68% working interest and was completed in mid July with a lateral length of 9300 feet.
At the end of July the well, which was still cleaning up after the Frac an increase in production was producing 2600 Boe per day.
With 72% of that being oil.
Unit has two additional red Fork wells already drilled that should be completed in the third quarter.
We have been successful in adding approximately 10200 net acres.
At an average price of about $1000 per acre within the pin sands prospect area since the beginning of the year.
Our Red Fork drilling inventory now stands at 30 to 40 operated in 10 to 15 non operated horizontal potential horizontal locations.
While we continue to have high expectations for the Red Fork play we have a limited dataset of seven horizontal wells.
However, we will be gathering additional data throughout the year, allowing us to provide further clarity of what to anticipate from this play.
The results from our Red Port program at our steady execution in our Sohot play have made a significant impact on oil volumes.
During this time that we aren't running rigs we will intensify our efforts to decrease expenses and we will continue with our strategy of adding acreage and prospects at low cost.
There's still provide drilling inventory at competitive funding development costs and cash flow margins.
We will also continue to evaluate organic and acquisition opportunities that could improve our cash margin.
And provide upside drilling inventory.
At this time I will now turn the call over to John for the drilling company update thanks Frank.
The commodity pricing fluctuations have continued during the second quarter, thereby affecting drilling rig activity levels.
We were able to maintain a consistent level of active rigs during the first two months of the quarter and then experienced an appreciable.
The increase in June .
We averaged 28.6 rigs operating during the quarter.
We're very pleased that we have been able to maintain 100% contracted right on our boss rigs since inception of the boss program in 2013.
During the first quarter, we placed our twelveth and 13th boss rigs into service.
And the second quarter, we obtained a long term contract for our 14th boss rig with one of our value to operators in North Dakota and also extend that.
Long term contracts on two other boss rigs that same operator has been using.
This is a trend complement for the quality of the boss rigs into the crews who operate.
The 14 Sprague will go into service in late fourth quarter.
We began the quarter with 32 rigs operating and closed the quarter with 25 rigs operating.
Currently we have 21 rigs operating with all 13 of our boss rigs than eight SCR rigs.
Average day rate for the second quarter was $18491.
An increase of $153 per day over the first quarter.
Average total daily revenue before intercompany eliminations.
It was $18962.
A decrease of $1377 from the first quarter.
This was due to early termination fees in the first quarter and second.
Excluding the early termination fees average total daily revenue for the quarter increased.
$307 over the first quarter.
Our total daily operating cost for intercompany eliminations increased by.
$472 for the second quarter as compared to the first.
The increase was primarily due to fewer rigs operating and expenses related to stacking rate.
The average per day operating margin for the second quarter for elimination of intercompany profits.
It was $5526.
Which is a decrease of $1850 from the previous quarter.
Largely due to early termination fees received during the first quarter.
Excluding their early termination fees the average per day operating margin for the quarter decreased to $167 from the first quarter.
Our non-GAAP .
Reconciliation can be found in today's press release.
Interest in our boss rigs remains very high and we strongly believe the boss rigs will be the anchor for the future of our contract drilling business.
In the meantime, we continued complete minor upgrades on this year rates as necessary to meet operator needs.
It is important to note that all of the above projects are being financed for operating cash flow and within our Capex budget.
At this time I'll turn the call over to Bob.
Pipeline.
Thank you John .
The payer continued solid financial and operational results during the second quarter of 2019.
We had a 19% increase in total throughput volume over the second quarter of 2018.
This is Derek met in seven new long lateral wells are Pittsburgh mill system in the Appalachian area and continuing to connect new wells to our expanded cash cost facility.
Operating profit before depreciation was $11.8 million from second quarter of 2019, which was a 10% decrease compared to the first quarter of 2019.
This decrease was almost entirely due to lower realized natural gas NGL prices between the quarters.
We invested approximately $17 million in capital projects during the second quarter of 2019.
Let them out.
Point $2 million spent on purchasing five existing rental compressors at our facility.
Majority of the remaining Apple expenditures for spend at our cash facility completing the installation of a new 60 million cubic foot per day, reading flat and connecting new wells to the system.
I will now discuss several of our key midstream assets.
At our Pittsburgh Mills gathering facility in Pennsylvania.
During the second quarter 2019, our average total gathered volume increased approximately 206 million per day.
This increase in gathered volume was due to adding a new seven well pad during the first quarter of 2019.
During the second quarter of 2019. These new wells continued to average at total of approximately 100 million per day.
This well pad that Qatar domestic compressor station, which has been up ready to handle the higher volume.
At our Hemphill facility in the second half handle the average total throughput volume for the site work and felt Mac team with approximately 72.9 million per day and total production of natural gas liquids increased approximately 289000 gallon per day.
During the second quarter with six new against drilling wells to the system.
At our cash and processing facility located in the central Oklahoma.
The average throughput volume for the second quarter 2019 increased to approximately 56.7 million.
Per day.
And natural gas liquids production increased approximately 270000 gallons per day.
Producers have continued to be active in this area.
In the second quarter, we connected nine new wells testing system.
This brings the total number of wells connected to the system since the first of this year.
We are continuing to connect new wells to the system with several additional well that can be connected in the third quarter.
We have completed construction and installation of a new 60 million cubic reading press.
From a processing plant.
This new processing plant is fully operational and has increased our total processing capacity on our cash.
Approximately 105 million per day.
In summary, we are pleased with second quarter results for our midstream segment.
Even in this lower price environment, we have added new wells with certain systems were actually growing and.
With the completion of the new rating plan. Our castle facility. We have increased our total processing capacity are able to handle expected additional volume from the system.
Additionally, with our established $200 million stand alone credit facility available, we continue to evaluate possible acquisition and expansion opportunities.
Which will contribute to the growth of the midstream segment in the future.
I'll now turn the call back over to Larry for his final comments.
Thank you Bob.
In summary, we continue to focus on the whole opportunity or core areas that provided the diversity of production mix outcome.
That could be helpful again different commodity backdrop.
As you heard or read for prospect, which we began developing late last year. So.
Shown very remarkable results.
The Red Fork in conjunction with our March Dan Rizzo via that should continue to be our contributors toward our move to increase oil production.
The boss drilling rig program, which we have been able to maintain 100% contracted rate provides.
Solidity to the quality of the rig design and customer acceptance.
We have been looking.
We have been looking for growth opportunities for our midstream business and have assembled to capital partners that financing arrangements necessary to dig deep was the appropriate.
Opportunity is identified.
Our company as crude has proven worthy of the past weathering storms and we will continue to do so.
At this time I'd like to turn the call over for questions.
Thank you we will now begin the question and answer session and we have a question. Please press Star then one on your Touchtone phone.
If you wish to be removed from the queue. Please press.
Brian or the hash key if you're using a speaker phone you may need to pick up.
First of all for Prosigna numbers once again and we have a question. Please press Star then one on your Touchtone phone.
And we have a question from Marshall Adkins from Raymond James.
Good morning, guys.
Larry I want to focus in on saying I think most people are paying attention to which is a free cash flow yield going forward.
Yes, Dean pretty hard this quarter from from gas prices.
Suffering.
Sounds like you're we're confident the differential.
Improves going forward and you're going to lower capex. So.
What's the likelihood over the back half of the year that you're you're actually going to be free cash flow positive.
Well I think it will be.
Lift everything totally cradle or two I think it will be cash flow positive.
We're not running any drilling rigs may up we had just a few wells left to complete.
Over 50% of their costs on our new boss drilling rig has already been incurred most of the components for that rig we booked an order like last year.
So capex is going to be pretty minimal the second half of the year, especially compared to what it was in the first half and we're fully expecting that to be dead be paid down significantly in the second half of the year.
All right then let's take that one step further and looking out to next year.
Is your strategy if oil prices cooperate strategy does ramp spending back up and spend the full cash flow or.
Generate additional free cash flow and pay down debt.
Yes.
Our focus is going to be continued to pay down debt.
We will.
We will quit drilling river, maybe the beginning of next year, we've started capital program back.
But part of that process through the capital budget will be.
The likelihood or the probability of paying down a bit as we spend capital.
Right.
Last one from me on.
Rig the new rig the additional rig going on a lot of people brand rigs right now.
What's the payback, what's the length of that contract is it like a three year contract. What do you anticipate your kind of payback term on new boss rig.
Marshall day contract on rig for 14.
And is only 18 months.
However, you have the two rigs that we have working for that same operator.
Those contracts were extended by the same amount of time virtually from the time, we signed the contract so.
In effect, we are getting four and a half years of guaranteed income which is right at the number that we expect home payout on the boss rig.
Okay. Thank you.
Thanks Mark.
And our next question comes from Neal Dingmann from Suntrust.
Good morning, guys.
My question is around that how you sort of balance your capex with cash flow I know you generally matches you all talked about that I'm just wondering given.
You know how good of eyepiece you saw there in a couple of these wells on the press release, maybe you know Larry for you or Frank how you think about potentially accelerating that to to drill on that are you know again is it sort of be tried and true you'll stick to the strategy of sort of slowing down to make sure that they match closer in the current period.
Well the Capex as I mentioned I mean, we're we're right now we're not planning are running any more rigs the risks this year at least through late late in the year.
Im sure our focus will be will we get back up to drilling assuming gas prices and oil prices are.
Still relative to where they are today, our focus is going to be in the March ahead and they report.
So proportionately, we will drill more wells.
In those two areas that we will have another.
Very good and then just last lastly can you just talk maybe a little bit on the.
The contract rig margins per day down a little bit I'm, just wondering what Tom was involved in you know given the.
Sort of what you're seeing now quarter to date, if you could talk about any color you're seeing so far this quarter.
Well the margins are.
Our view of the virtually.
Unchanged in the next quarter because as we.
The boss rigs are all under long term contracts, so we know where they're going to be.
The remaining rigs are the big question, Mark and on the open market now Dayrates are certainly not going increase plan.
There are so many rigs available.
We do feel like we can trim, a little bit more off our daily cost. So it may improve margins.
By 10%, but it's not going to be anything significantly.
Up or down.
Very good thanks, guys.
Once again, if you have a question. Please press Star then one on your Touchtone phone.
And we have a question from Sharon Chowdhry from DST Meridian.
Hey, guys. Thanks for taking my call.
Western I have is just looking at the performance of the superior midstream assets, how much of that business today is fee based courses contract based.
Approximately two thirds of the bid today, it's the bay.
And a third is pride density.
Today.
Understood. Thank you.
And just one more follow up and just looking at the drilling side of the business I understand the comments that going forward much of this is going to be.
You know contracted business, but I'm just trying to understand the weakness in the current quarter how much of that came from your decision to release the rigs have from your own business. My assumption is that some of these rigs were actually being used in the NP side.
Well, yeah, we were using them, we probably averaged three to four rigs during the second quarter that we're using now on a on a financial basis.
We eliminate any profits that we have all four of those rigs.
That.
That we show on a consolidated basis, so the bottom line.
It's not impacted whether we're running those rigs are not now revenues total expenses and you know those categories still show the inflow to fill those four rigs running for the quarter, but on the cash flow and earnings.
Any profits that we that we have are eliminated.
But you know as you lay down rigs of course more rigs you're running more rigs. It provides you the ability to spread fixed cost over.
A lot of that fixed cost continues whether you're running a rig or not so you do fewer rigs you run.
The less rigs you have to spread your fixed cost over so.
That makes sense.
Thank you and just one more follow up if I may.
How much of the boss rigs actually spent on one that answers. The question. My assumption is none of the boss makes where were being used in your N.B. operations.
No.
Now, we're running all SCR rigs.
Understood. Thank you very much that's it from my side.
Our next question comes from Teresa Fox from Stone Harbor.
Thank you I understand you have to boss rigs that are coming off contract in the third quarter. I'm is there any update on re contracting those did I Miss that.
I think there's only one boss rigs coming off contract.
In the third quarter.
And were were discussing that going forward with that operator.
There's.
Hi, Thanks, very little chance that is not going to continue with the same operator, but I'm just not.
Sure were terms or will be at this point.
Okay. Thank you.
As a reminder.
Question. Please press Star then one on your Touchtone phone.
We have no further questions at this time.
We want to thank you for joining us. This morning, we appreciate it very much.
Yeah.
No it's been a tough summer so things will improve.
We hope to see many of you have.
Entercom.
Later this I guess next week.
If you're there so thanks again for participating this morning.
Thank you ladies and gentlemen. This concludes today's conference. Thank you for participating you may now disconnect.