Unit Corporation (NYSE:UNT) Q1 2016 Earnings Conference Call August 4, 2016 11:00 AM ET
Larry Pinkston - President and Chief Executive Officer
David Merrill - Senior Vice President, Chief Financial Officer and Treasurer
Brad Guidry - Executive Vice President-Exploration
John Cromling - Executive Vice President-Drilling
Bob Parks - Manager and President-Superior Pipeline Company
Will Derrick - SunTrust
Praveen Narra - Raymond James
Charles Robertson - Cowen and Company
Bo McKenzie - Seaport Global
Welcome to the Unit Corporation Second Quarter 2016 Earnings Call. My name is Adrianne, 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 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. A reconciliation of these 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. You may begin.
Thanks Adrianne. Good morning everyone, we want to thank you for joining us this morning. With me today are David Merrill, Brad Guidry, John Cromling, Bob Parks and Frank Young. Each of these gentlemen will be providing you with updates concerning their segments, and after their comments we will take questions.
Before we begin the segment reports, I’d like to offer just some general remarks regarding the market and our progress. At the beginning of the year, our industry was marked by a great deal of uncertainty, as to how far commodity prices would fall, which resulted in acceleration of early rigs being laid down. As is our nature, we chose the path of balance sheet preservation by setting a capital expenditure budget for the year at a level well within anticipated cash flow.
Later in the second quarter, we began seeing signs of recovery process might be taking shape. According to Baker Hughes, weekly rig count data, U.S. land rig set a new record low with 374 rigs in late May. With the upturn prices, we began seeing a reactivation of rigs in the industry which have increased the rigs by 66 range [ph], according to the last week’s rig report. The monthly EI data, we are seeing monthly onshore lower ODA crude production decline from its peak rate by over 900,000 barrels per day while U.S. crude oil demand continues to rise.
U.S. natural gas production appears to be nearing an inflection point due to the lower level of drilling activity despite rig efficiency. Summer heat, power generation and LNG export demand appear to be providing some relief as well. In recent weeks we have seen a pullback in prices, frustratingly similar pattern to the one we saw last year. We remain encouraged with many of the optimistic signs that we are seeing over the last few months. We however are staying in the course, managing our expenditures to make sure our balance sheet remains in solid state. I’ll believe you will see a number of encouraging achievements from the different segments in the reports to come. Maintaining a growing shareholder value is of critical importance to us.
We will now turn the call over to David Merrill.
Good morning everyone. We reported a net loss for the second quarter of 72.1 million or $0.44, which included a 74.3 million pretax non-cash steel ceiling test write-down in the carrying value of the Company’s oil and gas property.
Adjusted net loss, which excluded the impact of non-cash derivatives and the ceiling test write-down was 7.4 million or $0.15 per share. Our non-GAAP financial measures reconciliation is included in our press release.
For the oil and natural gas segment, revenue for the second quarter increased 19% over the first quarter because of higher commodity prices, somewhat offset by a decrease in production. Operating cost for the second quarter were essentially unchanged from the first quarter.
For the contract drilling segment, revenue for the second quarter decreased 37% from the first quarter because of the decrease in the number of drilling rigs operating and lower early termination fee. Operating cost for the second quarter decreased 31% from the first quarter, because of fewer drilling rigs operating.
For the midstream segment, revenue for the second quarter increased 14% over the first quarter because of increases in liquids-sold and gas gathered volumes and higher natural gas liquids prices. Operating cost for the second quarter increased 4% over the first quarter because of higher gas purchase price.
The effective income tax rate for the second quarter was 37.3%, and we anticipate the effective rate for the balance of 2016 to be approximately the same. We ended the second quarter of 2016 with total long-term debt of 875.1 million, a reduction of 23.6 million from the end of the first quarter, consisting of 639.1 million of senior subordinated notes net of unamortized discount and debt issuance cost and 236 million of borrowings under our credit agreement.
In early April, we amended our credit agreement, which among other things set our elected commitment and borrowing base at 475 million and established our maximum senior leverage covenants to be no greater than 2.75 times EBITDA through the first quarter of 2019. We ended the second quarter at 0.82 times. The borrowing base consists of our oil and gas properties and the midstream business, and does not include our fleet of drilling rigs.
We completed the mid-year review of our capital expenditure budget for 2016, with our budget remaining unchanged from the beginning of the year, which is below our anticipated cash flow and proceeds from non-core asset sales. Our capital expenditure budget is 161 million to 187 million, and by segment the 2016 capital expenditures are 109 million to 131 million for the oil and natural gas segment; 9 million to 11 million for the contract drilling segment, out of which 56% to 69% is associated with certain components for future Walsh rig and 22 million to 24 million for the midstream segment, out of which 52% to 57% is associated with the fee based project in the Appalachian area.
At this time, I’ll turn the call over to Brad Guidry.
Good morning. In the SOHOT Hoxbar area, operational results for the second quarter were in line with our expectations, as production per day decreased about 14% as compared to the prior quarter. The decrease is attributable to the natural decline rate associated with the existing wells that were first completed in the later part of 2015 and in the first quarter of 2016 and because we only completed one new well during the quarter.
The new horizontal Marchand sand oil wells completed during the quarter had an average 30 day production rate of approximately 720 barrels of oil equivalent per day, which is about 13% lower than our current type curve. However our current type curve continues to have estimated ultimate recovery of about 550,000 barrels of oil equivalent that is based on historical production from 24 horizontal Marchand wells drilled to date within the SOHOT core area.
Current expectations are to pick up the unit rig and resume drilling Marchand sand oil wells within the SOHOT core area in the fourth quarter of this year. Our leasehold in SOHOT core increased 3% during the second quarter, to over 19,000 net acres.
In the Texas Panhandle, operation results for the second quarter were also in line with our expectation as production per day decreased 7% as compared to the prior quarter due the natural decline of visiting wells and only completing one new well during the quarter. In April we completed the Dixon 5554 #1H, which is our first extended lateral horizontal well in the Buffalo Wallow field, utilizing our largest frac to date consisting of approximately 290,000 barrels of water and 9.2 pound of sand spread over 45 frac stages. The Dixon well which unit has working interest exceeding 99%, with completed C1 lens at Granite Wash sand well [ph]. It had an extended lateral approximately 7,500 feet which is 67% longer than our typical lateral.
Since April, rates from Dixon have continued to increase and currently producing at approximately 12.1 million cubic feet of gas equivalent per day, consisting of 43% gas, 15% oil and 42% natural gas liquids. Production rates from the well at end of July were approximately 55% higher than our pre drilled projected extended lateral type curve. Additionally the flowing casing pressure of 1100 PSI is still above line pressure indicating that production rate and the production curves could be even higher if the well was full down to the line pressure of 140 PSI.
Although more production history is needed before having a better hand on the reserves and the rate of return associated with the extend of lateral well, the significant increase in Q1 [ph] under production to date as compared to our extended lateral type curve is encouraging. This is especially true in light of the fact that our type curve has relatively return of approximately 35% to Unit Petroleum Company and 58% to Unit Corporation when superior pipeline profit margins are included.
Within Buffalo Wallow we have 18 to 20 Granite Wash C1 extended lateral oil locations identified. Additionally our results from drilling 4,500 foot laterals in the Granite Wash A and G enable [ph] indicates 7,500 extended laterals in these two zones, should have similar corporate rates of returns as to see one enable, which would add another 40 to 50 locations. Beyond A, C1 and the G lenses the Granite Wash in Buffalo Wallow field includes eight additional lenses, providing us with potential to open then we have in excess of 200 extended lateral wells across the field. While the gas, oil and natural gas prices required for these [indiscernible] eight additional lenses to be economic or currently uncertain, We believe our extended lateral economics maybe further improved by increasing our frac size and or extending the length of our laterals to greater than 9,000 feet. Current expectations are to begin one or two rig Granite Wash extended lateral development program in the Buffalo Wallow field in late fourth quarter of 2016 or the first quarter of 2017.
In the Wilcox we achieved record production of approximately 97 million cubic feet of gas equivalent per day for the second quarter of 2016. This is a 9% increase over the first quarter at ‘16 and 25% increase over the second quarter of 2015. The production growth is attributed to new horizontal wells and behind pipe3 completions that had first oil and gas sales primarily in the first quarter of 2016. Activity during the quarter is reduced as plan resulting in no new horizontal well completions and only one new behind pipe 3 completion during the second quarter.
Through the end of the second quarter we have completed a total of 4 behind pipe 3 completions that are currently producing approximately 17 million cubic feet of gas equivalent per day. At the beginning of the year prior to these completion of same four wells were producing approximately 700 mcef per day or about 4% of the current rate. The average cost for recompletion is approximately 500,000 per well. During the second half of this year, we anticipate, recompleting of approximately four to six new behind pipe zones that should result in 15% to 20% annual growth for the Wilcox program.
We have a current inventory of approximately 30 to 35 new behind pipe rig completions, primarily in the Gilly Field that extracted to be completed over the next five years. Current expectations are to resume drilling in the Wilcox with unit rig at the end of this year at first quarter of 2017.
I’ll turn the call over to John for the drilling company updates.
Thank you Brad, the second quarter was very challenging for our contract drilling segment as we continue to face the depressed demand for drilling services. The average day rate for the second quarter was $18,585, an increase of $193 per day over the first quarter. The average total daily revenue before intercompany eliminations and including early contract termination fees was $19,680, which was a decrease of $793 from the first quarter.
Our total daily operating cost before intercompany eliminations, increased by $789 for the second quarter as compared to the first. This increase in daily cost is largely attributable to having fewer rig days of which to spread fixed cost. The average per day operating margin for the second quarter before the elimination of intercompany profits and bad debt expense was $4,259, which is $1,392 per day decrease from the first quarter.
The reduction in total revenue was attributable to the lower levels of utilization and $1,068 per day decrease in early payments for the quarter. Our non-GAAP reconciliation can be found in today’s release. We began the second quarter with rigs operating which dropped 13 before rebounding to 16 by quarter’s end. Our activity level was fairly consistent with the industry activity levels. We were able to put three additional ideal drilling rigs back to work. Also we have contracted another rig to begin operations later this month which we’re personally upgrading with washing system, 7500 PSI mud system and hydraulic catalog. This rig will be under six month contract and will be working in the Permian. We are continuing to receiving queries, how this ultimately plays out will be dependent on commodity pricings currently seven of the eights rigs under contract have 16 active rigs.
We are still confident that we will manage through the current market cycle because of our history of being financially prudent. Our long-term relationships of key operators and the versatility of our fleet in our people. We have initiated several cost saving programs and reduced our CapEx budget to maintain our financial liquidity. The recent cost saving measures of staff reductions, consolidations and salary reductions have lowered the daily direct cost in June and we will continue to see the results of this for the balance of the year.
At this time, I'll turn the call over to Bob, for the Superior Pipeline update.
Thank you, John. Despite the continued low price environment in the second quarter, midstream segment was able to achieve strong financial and operational result. During the second quarter of 2016, the increase volume by 15% compared to the first quarter of 2016 and by 21% over the second quarter of 2015. This increase is largely due to additional volumes from well connected to our Apalachin [ph] gathering systems as well as additional volume associated with our second gathering system at Southeast Texas. We continue to focus on monitoring and controlling both our G&A cost and our field direct operating expenses. During the first half of this year, we have been able to reduce both G&A and operating expenses compared to our expected budget amount. As of the end of the second quarter, we operated 26 exact gathering systems in Oklahoma, Texas, Kansas, Pennsylvania and West Virginia, which include approximately 150 miles of pipeline and 14 natural gas processing plants. Just finally connecting 17 new wells to our facility during the second quarter, our total throughput volume continue to improve.
During the second quarter, we added a new two well pad to our Pittsburgh Mills system, and we added a new three well pad to our Snow Shoe system. Both of these gathering systems are located in the Appalachian area. During the first half of 2015, our NGL gallon sold continue to be lower than previous years due to the fact that we are operating in a more profitable ethane rejection mode at most of our facilities due to impressed ethane prices during the quarter.
During the first half of 2016, we invested $8.5 million of capital project as compared to $24.3 million in the first half of 2015. Our total 2016 capital expenditures are estimated to range between $22 million to $24 million for the year. I’ll now focus on several key areas of our midstream business.
In the Mississippian play in north central Oklahoma at our Bellmon processing facility, during the second quarter of 2016, we connected 10 existing wells to this gathering system. The average throughput volume at this facility was approximately 34 million cubic feet per day. We have the ability to process approximately 90 million cubic feet per day from two processing skids at this facility.
Also during the second quarter of this year, we increased our natural gas liquids production to approximately 130,800 gallons per day due to operating in ethane recovery mode for a portion of the quarter. At our segment gathering system located in Southeast Texas during the second quarter, our average transported volume increased by over 5 million cubic feet per day to just over 90 million cubic feet per day. We connected three new wells to this facility during the first half of this year. With the completion of the gas pipeline extension project, and the installation of additional dehydration equipment, the overall gathering at dehydration of pads to the system has increased to 120 million cubic feet per day.
In the Appalachian area, at our Pittsburgh Mills gathering facility, we continued to connect wells and increased total throughput volume. During the first half of 2016, we connected three new well pads for the total of 12 new wells, and the average throughput volume for the second quarter was approximately 142 million cubic feet per day of dry natural gas.
Additionally, we completed the connection of our next well pad, the Wallow pad, which began deploying gas in July of 2016. The Wallow well pad is located on the northern portion of our gathering system, and it’s a six well pad. With these wells connected to our system, we anticipate our throughput volume to remain at approximately 150 million cubic feet per day for the remainder of this year.
Additionally in the Appalachian area, at our Snow Shoe gathering system located in Centre County, Pennsylvania, for the first half of 2016, we connected three well pads from two producers for a total of six wells. The throughput volume averaged 14 million cubic feet per day for the second quarter of 2016. Since compression will not be required initially for this facility, we are postponing the construction of compressor stations until it’s required in future day.
In summary, as we reached the mid-point of the year, its attractive financial results for the first half of this year, while returning the upside exposure with our commodity based systems and prices in the future. As liquids prices continue to be depressed we are operating at full ethane rejection at most of our processing facilities, which were recently now recovered compared to previous years. With the continuous excess of our Appalachian area systems, along with our focus on monitoring and drilling cost, we feel the midstream segment is very well positioned to 2016 with very best financial and operational results.
At this time, I’ll turn the call back over to Larry.
Thank you, Bob. Before moving to the Q&A, I would like just once again just highlight a few points. As we stated, we set our budget to focus on our balance sheet. As we noted, we were able to reduce our bank debt by over $200 million during the quarter. We were very pleased with the [indiscernible] completed activity results in the Wilcox, where extended lateral appears to offer a great opportunity for us in the future. We were able to participate in the drilling reactivation process, re-contracting one RO BOSS rig, returning a couple of these RO rigs back to service. The midstream segment, we are seeing some strong results, and that picked the natural gas liquid pricing offers a tremendous opportunity for growing that segment. Although capital expenditure budget for the year was see at a very modest level, we are not lazy, you can see that we are being idle, we have sought to create new and enhance very new opportunities.
Adrian, I’d now like to turn the call over for question.
Thank you. We will now begin the question-and-answer session. [Operator Instructions] And our first question comes from Will Derrick from SunTrust. Please go ahead.
Good morning guys, nice update. Now I guess the first question, Larry for either you or Brad, looking at Buffalo, Wallow bringing rigs in later this year. How should we think about that program? Is that something that you think is going to extend through 2017 for the whole year? I guess what are your initial thoughts there?
Let me just make one comment, and I’ll let Brad fill in all of the details as usual, but that’s contributing our commodity prices, $40 a barrel, is going to be maybe difficult to keep one rig running in Granite Wash with what we want to do in the Wilcox and/or the Hoxbar but $40 keep rigs running in all three of our major core areas for 2017. Brad, do you want to add anything to that.
Yeah, what I’d say is, Larry touched on it but if oil prices stay well and gas prices tend to remain a little bit stronger, I think the Granite Wash becomes a little bit more viable opportunity for us. So my gut feel is yes we will run rig in 2017 in the Granite Wash, and if things pickup from there, I’d say the possibility of running two rigs is real if the capital is provided.
Okay, thanks. And then also looking at gas shifting to Wilcox, can you remind us, I guess two things, one the cost and what those recompletions are, and then two how many more you expect to complete through to the end of this year?
Yeah. The recompletions, there is really different types of recompletions, but we’ve tried to put it into a bucket, so what we are talking about represents really an average result that we should expect. We have some that are well above the average, some that will be below the average, but in general a recompletion is about $500,000. We have an inventory of 30 to 35 recompletions right now, and that when I say that recompletion that’s a one that we feel that will meet this average that we are looking at. The rest of this year we plan on doing probably four to six additional recompletions during the second half of the year.
Okay, great. Thank you all.
And your next question comes from Praveen Narra from Raymond James. Please go ahead.
Hi, good morning guys.
In terms of the incremental rig ahead obviously you said it’s depending on commodity sensitivity, but in terms of the pace and where they go first, is it the right way to think about it that rig at Granite Walsh than maybe Hoxbar or help me understand the - where the incrementals go in order?
Yeah the current plan right now is the Hoxbar will get the first rig and that would be mid-October, that’s what we are planning, the Granite Walsh towards the end of the year and then Wilcox would also be towards the end of the year, maybe into the first quarter. But the Hoxbar, we have some lease explorations that are coming out. So we want to make sure we get the rig in there to save those leases and then the Wilcox and then Granite Walsh are both more operational. We don’t have any explorations to meet there but we want to get it in to obviously get back on our production growth mode for 2017.
Okay perfect. And then on the drilling side, can you guys give us a sense of what you are hearing, I know you talked about potential opportunities for [indiscernible] with commodity pullback, are you doing anything for customers in terms of changes of plan over the past month or so.
We haven’t seen any changes in the last month as far as the decrease, by the same token we haven’t seen an increase in the enquiries over the last two or three weeks that we did over to six weeks For the six weeks. So, it’s not worse, but it’s not better.
Okay, perfect. Thank you, guys, very much.
And our next question comes from Charles Robertson from Cowen and Company. Please go ahead.
Good morning, guys. We’ll stay on contract drilling side of the question. You said you signed up a six-month contract. They're adding a Walking system 7500 PSI catwalks. Any color as to why the customer would prefer an upgrade over a new build and what the advantages are there and then I have a query for the E&P side?
Well, number one we don't have a new bill to offer them and so they took it and it’s a customer that has that business for a long time and they like the way we operate. So, that particular case is the reason. Also this regular upgrading would be able to offer most of the same advantages as Wash A [ph] not totally, but very competitive.
Do you have additional rigs that would fit that category as well for the upgrade?
Certainly, certainly. Several of our SCR rigs would be able to do the same thing and many of those we already have. We have many more than we can do.
And I guess turning a little here to the buffalo wallow, very encouraging. Well, you said you looked to take it out to 9000 foot laterals there. What are you seeing and any additional color on the completion side? Obviously it was very intense. Any sense that you can move up on the intensity and what does that produce?
Yeah. Hey, Charles, Frank Young is also on the call and he is the Senior VP over that operation. So, I’m going to let him address that question.
Charles, this is Frank. The completion we did had 45 stages and each stage was about 200 feet or 175 feet apart from each other. That frac was about 1250 pounds per lateral foot state and we think that we can increase that to around 1500 pounds per foot and improve the completion further. Previous to this frac, the largest frac we had done on a pounds per lateral foot state was about 950 or 1000 pounds per foot. So, we're continuing to learn and optimize our completions in Buffalo Wallow and we still have some room to go there.
The other encouraging part about Buffalo Wallow is that our AFP carts there, our type curve and our type curve cost is about approximately $5.7 million. The current cost on the Dixon Well was about $5.4 million. We were able to beat our cost there and we think that we can continue that. And then lastly we were able to drill a 7500-foot lateral without much difficulty. We were able to do it in 30 days, which was 10 days ahead of our plan and looking at the hydraulics that we saw in the torque and drag while drilling that well, we think we can go out to 9000 feet which would improve the well further. As it is, the well is producing about 55% higher rate right now than what our type curve is and our cumulative production from the well through a 110 days is about 26% higher than the type curve.
Definitely very impressive results. Thanks.
And the next question comes from Bo McKenzie from Seaport Global. Please go ahead.
Hey, guys. Congratulations on a good quarter really good quarter. What does it take in terms of prices to accelerate to recompletion activity done in the Wilcox. The numbers were astounding so far on the four wells. Is it just a matter of learning curve with the kind of inventory that you see out there in the [indiscernible] what does it take to pick that up, because these commodity prices are just more comfortable in the program?
Yeah, this is Brad. It's not as much of the commodity price, because of the low capital expenditures and the results were finding their economic. So it's not even at a lower price. They would be - what dictates mostly is these are vertical wells that have been drilled that essentially have multiple [indiscernible]. So, the well that we recomplete we're sensually just moving up to another Wilcox in the well. So, the wells that we're talking about are currently producing and a lot of those wells are producing at very economic levels. So it's not a matter of you want to leave a well that's currently making money to recomplete to a new zone, because it's very hard mechanically to move back down whole once you move up. So, it's really more of a question of timing is driven more by the results that we're getting from the well. Your question might be why don't you just add them altogether and the answer to that is because there's a pressure difference between these wells as you produce the current zone, the formation pressure of that zone decreases when you move up to a new zone. Typically it's at a virgin pressure and you can't put those two zones together initially. So, it's more dictated by the wells when we do the recompletions. But what we've seen and when we have accelerated the number we're doing this year is greater than what we did last year and we will continue to do that. We're looking at our threshold of what economic level do we move up that compared to where we were in the past, but that's really the main driver of that program.
And 500,000 [indiscernible] not doing any fracs [indiscernible] the most part?
No, it is fracing, but these are vertical frac single zone. So, frac costs to come down, we are on a typical track on a recompletion accounts for about 100,000 to 150,000 of that cost.
All right. And then on the rig side, just in general, [indiscernible] about what the spread is between the new contracting rates on [indiscernible] versus a comparable SCR with the 1500 horsepower that’s not as much as the TNB to be competitive with the [indiscernible]?
In regards to the day rates?
Right now current prices probably $500 to $2000 a day difference.
Is there much of a difference in operating cost doing the rigs?
A little bit that that’s probably less than $500 a day.
Okay and your capital budget on the rig side is not very big, so I assume the upgrades are not really big. What kind of payback are you getting on those incremental investment you're putting into the SCR to put the walking in the bigger mud pump [indiscernible]?
Well, the CapEx costs to do that is a little bit distorted in this case, but as we already owned all the components in order to make those changes, because that's been a process that we've done for several years and we have always maintained an inventory of equipment to be able to do that when the opportunity came up. So, this one is a little bit unique, because that cost would be relatively small and it will be included in the CapEx budget, but it’s not a cheap process to do. The return will be adequate that will get our money back in the term of the contract.
Okay, good deal. All right, thanks a lot. Thank you and congratulations.
[Operator Instructions] And we have no further questions at this time. I’ll turn the call back over to Larry Pinkston for final comments.
Thanks everybody for joining us here this morning. It’s a very good call, it’s a good quarter. We’re looking forward to settle things in the third quarter, but we still are seeing some encouraging things with some of the discouraging things, but at least there is some encouraging things now, which is a little different. We will be presenting at the Intercom Conference in a couple of weeks. I think we're presenting on the 17th, Wednesday morning of the Intercom Conference. We hope to see many of you there. Thanks again.
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