Unit Corporation's CEO Presents at Bank of America/Merrill Lynch Leveraged Finance Conference (Transcript)

Dec. 4.12 | About: Unit Corporation (UNT)

Unit Corporation (NYSE:UNT)

Bank of America/Merrill Lynch Leveraged Finance Conference

December 04, 2012, 07:30 a.m. ET


Larry Pinkston - President and CEO

David Merrill - CFO and Treasurer

Unidentified Analyst

We have Unit Corp from Tulsa, Oklahoma. We have CEO, Larry Pinkston; and CFO, David Merrill here with us today. So, Larry go ahead.

Larry Pinkston

Thank you, George. I appreciate everyone joining this sunshine morning. We are very excited about, (inaudible) share some of those exciting things with you this morning.

We are somewhat unique in energy business. We have three segments; we have a contract drilling segment that we currently have 127 drilling rigs in. We have an E&P segment that we finished last year with 116 million barrels of oil equivalent reserves and we have a midstream segment that now has little over 1100 miles of mostly gas gathering pipelines, gas plants, processing plants and treating facilities.

We have always considered one of our major strengths is our corporate structure. What our corporate structure allows us to do is direct investment into whichever segment that we think we can achieve the best rate of return for our shareholders.

The cycles in the three segments are very same. We see cycles where operators are wanting drilling rigs very quickly and we build drilling rigs for them. We see cycles where they don't want any drilling rigs. We have the option if we don't want to add, if we don't need to add drilling rigs we can grow our oil and gas properties more aggressively or we can invest more into the midstream business. The oil and gas segment is really the segment that we can kind of control our growth. The other two segments are mostly opportunistic driven when operators don't need mid stream operations or when they don't need additional rigs. There is not much we can do to force [when they take it].

That our oil and gas segment is our most consistent growth story. We have a good long history to show them. In our drilling segment over the last 10 years we have grown into rig fleet on average on 69%. And our E&P segment we replaced over the last 10 years 195% of our annual production with new reserves. And our midstream segment which is our newest segment that we have gotten into really in 2004 our amount of natural gas process has grown by over 260% and amount of natural gas liquids that we have sold has grown over 660%.

In our E&P segment, really up until 2008, we have been primarily a natural gas company. It was because we preferred natural gas [over oil]. We just over as more opportunities to grow natural gas in United States and there was all of the economic or better to grow natural gas reserves that changed in 2008 with the meltdown. We began to focus almost entirely on growing our liquids production. Today we have three core plays, one is the Granite Wash and our acreage is mostly in the Texas Panhandle, the other is Marmaton play, a shallow oil play in Oklahoma Panhandle primarily in Beaver County. And the third is the Wilcox play which is in Southeast Texas.

In September, we closed on a biggest transaction in Unit’s history. We bought oil and gas properties of Noble Energy for about $617 million. The transaction was all cash. We paid for the transaction with add on to our public debt offering (inaudible). And the proceeds of some two properties non-core properties that we sold that always caused in September. The transaction is accretive on a cash flow per share it will be accretive on earnings and cash flow per share both in 2013 and going forward.

The primary reason why we bought it, we liked the properties. The properties we have in our backyard, there are an areas that we have been drilling both on a rig side and on our E&P side for the last 30 years. We are very aware of the risk. What we acquired with 44 million barrels of oil equivalent reserves. Production in April was about 10,000 barrels of oil equivalent per day and we acquired 84,000 net acres and most importantly in that 84,000 net acres 80,000 of those were HBP. So, we are not going to be in a position of having to drill the acreage in order to save it, we can drill it when it makes the most economic sense. And that’s very, very important in the volatile industry as the energy industry but it kind of shows where the acreage is most of the Granite Wash acreage of the play which is about 25,000 acres in this area this is our core area of the Granite Wash also, that was really although we analyze in the transaction those of Granite Wash acreage.

We come up with over 600 possible locations just on that part of the acreage the other 60,000 acres are spread out across Northwestern Oklahoma and Oklahoma Panhandle includes the (inaudible) some acreage that covers about all of the plays that’s been around forever in Western Oklahoma. But our focus was on the Granite Wash which was the most (inaudible) only a couple horizontal wells and there are 25,000 acres drilled many, many vertical wells which that’s important also, because it gives you well controlled helps you direct, helps you control the drilling process of the horizontal well. So, they are very underdeveloped from a horizontal perspective. It has about seven different formations in the Granite Wash primarily the two formations that Noble had produced was [AMB] formations. In our acreage we have production out of five additional zones from A all the way through the G now. So, we are very anxious to get started in the area.

One of the enticing things about the acquisition was, it was an area that all three segments of the company are going to be able to benefit from are midstream company has a gas processing plant that’s about four miles away from the Granite Wash production to current processing agreement expires on that acreage at the end of ‘14, by the end gas production we feel should be quite a bit higher than where it is today. But just from the processing operations of the Granite Wash it could be the potential of the 15 to 20 million a year of cash flow just from a processing. That our plans are to put couple of rigs in the new Granite Wash area early in 2013 hopefully by the end of 2013 we will be up to 5 to 6 to possibly 7 rigs in the field but we want to be, we will doing pad drilling as we move across the field which is the most efficient. We want to test some of the lower zones. The lower zones are not production characteristics, (inaudible) in each of the zones so we need to make sure we know what each zone characteristics are that we will get started on that in the first quarter of 2013.

As we put rigs in the field our average working interest in the field is about 65%, of the rigs other 35% ownership of the properties will be cash contribution to our drilling segment from a third-party none of that was figured into the financial analysis on our bid for the properties. So, those kinds of things is a good example of how the three segments of the company were in a transaction like this. A pure play company would not be able to achieve those kinds of economics and developing out of play. But it's a very, very exciting play; it gives us many, many years of future drilling opportunities. And again remember all we mostly talked about here is the Granite Wash over 60,000 acres spread across Northwestern Oklahoma and it is in some very good areas for development drilling.

The (inaudible) that we sold a couple of non-core properties; one of those properties was one of our Bakken positions down to the south. Bakken is an area that we like very, very much. We got established in the Bakken really about 5 or 6 years ago. We were really never able to establish a big enough acreage position as we become big enough to warrant its own operation when we saw acreage cost go up, so dramatically in the area. The economics we can never make the economics compare to the economics we were achieving in Western Oklahoma and Texas Panhandle especially when you consider the contribution from all three segments of every dollar that we spent in western Oklahoma and Texas Panhandle area.

That’s when we made the decision that it wasn’t going to be an area that we are going to grow, we know we would be selling it at some point in time, prior to this year it really didn’t make sense to market it. We didn’t have really a use of the proceeds, we didn’t have properties that we have identified with the Noble acquisition both transactions really fit to come together very, very well. We were actually able to close the Noble the sale of the properties about two weeks after we had closed the purchase of the Noble properties. So, timing was wonderful on both transactions.

We received about $220 million net production out of the field in the second quarter as our share of the production was about 1000 barrels a day in the second quarter. We owned 12 to 15% interest in these properties, properties that we didn’t operate. 100% of the working interest (inaudible) including the operator it was part of the QEP acquisition that QEP brought in the Bakken.

We had about 5.7 million barrels of oil equivalent reserves booked and only 30% of those is proved developed so most of the reserves is proved undeveloped. We are very, very happy with the price that we have got. This (inaudible) north 2600 acres has about 600 barrels of oil production per day to net our interest. We probably will be out marketing it over net six months in the process now. It's not going to be done by the end of the year but it doesn’t make sense for us to us, it's all HBP now. So, that makes it much more attractive to potential buyer also.

The acreage up over Montana, we drilled over first well on that acreage. we don’t have any idea what kind of position or what kind of results that areas we are going to have but it would be something we would look at doing something with also probably not quickly though.

Reserves we finished the year with 116 million barrels of oil equivalent was up 12% over 2011 over 2010. Your goal each and every year for the last 28 years has been to replace at least 150% of each year’s production with new reserves. We have done that each and every year for the last 28 years of course with the Noble acquisition this year that number is going to be north of 400% of production replacement. Make sure our average is really look good and we see how we do next year as far as achieving better results in that. But that’s sort of what we are, we are a consistent growth story, we have grown to some very volatile times as you can imagine over the last 28 years, certainly been very, very consistent.

Production last year was 33,000 barrels of oil equivalent that was up 22% over 2010. This year our guidance is 38 to 39,000 barrels includes a Noble production from Nobel. We will be at 15 to 18%; we only got to include production out of Noble for basically the fourth quarter. As I mentioned in 2008, for the change or the focus on liquids entail in 2011, there are liquids grew about 55% between those two years, this year our liquids should grow somewhere around another 25%, so making really good strides at increasing our liquids production. Think our liquids production in the third quarter was around 44% of our total production. Noble was not quite as rich in oil, Noble is rich in liquids that with the sale of the Bakken properties fourth quarter liquids production is going to be closer to about 40%.

In the Granite Wash play this is an area that we have been drilling wells in for as long as I can’t remember which get shorter and shorter though again I guess. But over 30 years we have been in the Texas Panhandle. We drilled 38 horizontal wells; we have 30 days average IP rates on since 2011. Average IP rates have been about 5.1 million a day that’s about 50% liquids. The wells cost about $5.5 million to drill. We have reserve booking somewhere around 4 Bcf equivalent or reserves per well. Again that’s about 50% liquids or midstream company processes oil and gas from this area for us so we capture that margin also that a pure play wouldn’t be able to capture. We will spend somewhere around 130 million this year, drill somewhere around 32 wells. We started of the year with 4 rigs, we got the oil, we got out program drilled mush quicker this year than we thought going into the year. We are currently running two rigs that will be going back to 4 rigs in early 2013 and the total Granite Wash field hopefully be up in 8 to 10 rig category which includes Noble properties in our own properties.

As I mentioned Noble brought about 600 potential drilling locations. We have about 200 potential locations on our legacy acreage. So, 800 possible locations just in the Granite Wash going forward and we will be adding rigs under the field in order to speed up that drilling of that inventory.

In the Marmaton which is a pretty recent and new area for us. It really got started in 2011 that’s a shallow oil field production out of the field is about 82, 83% oil, it's about 7 or 8% natural gas liquids, process natural gas liquids is very, very rich natural gas fields. The wells are about 6,000 foot vertical deep, the horizontals all but two of the wells that we drilled and completed have lateral of about 4500 feet. We have drilled two long laterals and the 9500 foot category. We are very limited in Oklahoma. Legally that was in corporation commission on the long laterals probably for another year or so is not going to be whole lot more long laterals drilled in the area. But we had some very, very nice reserves. Short laterals wells cost about $2.7 million to drill. We are average booking about 130,000 barrels of oil equivalent per well. Well has come online with 30 day IP, where average IP rates little over 300 barrels per day and get your money back very, very quick.

The investments are in 1.5 to 2 times your initial investment with $90 oil and you are looking at rate of returns in the 40 to 45% range. The long laterals two that we have online the average 30 day production rate out of those two was 760 barrels per day. Those wells cost about $4.5 million to drill. So, cheaper than drilling in two short laterals and we help going forward which again we think it would probably be a year to 18 months before we have really achieve that on a large scale basis but the economics should be much, much better on the long laterals when we are able to do that. But we have about 10,000 acres in the field now. We have got 150 locations identified and that’s one well per section basically to get the acreage saved after that we will back in the field drilling development wells. So, very fractured play. The economics are you are looking at 150 to 200,000 barrels when you find how they fractured natural fracturing areas.

We will have better areas to identified over the next 6 to 9 months. So, hopefully we will drill more of the higher end wells lesser of the lower reserve wells. And wait for process to come up to where you can drill 30 to 40,000 barrels and achieve very nice economics.

In the Wilcox, it's actually is an area that we drilled the first well, Discovery well in 2003. We drilled 109 wells in the field since then with about 72% success ratio. This is conventional drilling and it's not horizontal. Oils range from 11,000 to 13.5, 14,000 deep, most of the wells that we drilled thus far have been in the Middle Wilcox. We started drilling wells in the upper lower Wilcox. One of the areas that we just drilled into is the most significant discovery we had in the field since we have been there. It's about 1000 acreage structure. We found net pay of about 226 feet in the play. In the first well we drilled three additional wells since then to confirm the field, but we are taking 1000 acre structure.

It's somewhere around 230 Bcf gross, 160 Bcf net and the great thing about the field is we think we have 6 additional wells or a total of 10 wells. I will be (inaudible) all of these reserves on the books of Unit. So, for 55 to $60 million you are going to be able to bring 160 Bcf in the Unit, we will look at some possibility of some production enhancement wells after then, but very, very significant field for us, about far the biggest (inaudible) and a single transaction we’ve had at Unit. And 30 years was out been there, but we are running one rig and we will probably we will start off next year with one rig, hopefully but mid-year we will be at 2 rigs. Our guys, our geologist we have to have 3D in order to drill the process field. Our guys are very excited about the possibility of finding this lower structure across our other acreage in the area, whether it's a successful as this area or not, they have no way of telling that until you drill, that they are very confident that the structure exist.

Moving into our drilling. As I mentioned we currently have 127 rigs. We have added one new rig this year, and we have no plans to add any additional rigs. We love to add rigs but we want two to three year contracts before we add rigs. Right now operators are not demanding any new rigs. We have refurbished 19 rigs. We will continue to do that as demand increases, as demand dictates one of the most aggressive growth areas right now that we are seeing in our areas of operation is in the Northern Oklahoma and the Mississippi. There is going to have to be a lot more rigs added to that play with all of the leasing activities that’s happened.

Utilization for the year we averaged 77 rigs, 73 for the third quarter, we are current running 82 rigs. The market has softened by far the majority of the reasons that we have been given as to why operators released rigs as they are out of budget. And that we heard that before so the thing so far that makes me little bit more comfortable that the rig count is going to come back at the first year. We actually had operators that released rigs. In October we already signed contracts to put them back to work in January.

So, in our E&P division that’s definitely what happened? We got the wells drilled earlier than we anticipated. We are planning on gearing back up in January. So, I think you will see a rig uptick really in the first quarter. How far it goes beyond that it will depend on commodity prices but I do think you will see an uptick in the rig count.

So, the utilization of our rig fleet by size also most utilized areas or the 12 to 1700 horsepower, those are drilling in the deeper horizontal wells, maybe 700 to 1000 horsepower rigs is what’s been used in the Mississippian play. We have rigs available as that play continues to grow, again its right in our backyard. Its 100 miles from our main office or main facility that maintenance facility. There is nobody going to be able to maintain the rigs, run rigs more efficiently than we will be able to as Mississippian play grows.

Dayrates really have maintained the sales very, very well. We are about $20,000 average for the 9 months; we are about $20,000 for the third quarter. What’s holding if the rig rates is the term contracts most of the rigs has been released on the well contracts some of the lower dayrate rigs but not really see the dayrate dropping significantly, especially if we start picking up rigs again in the first quarter and utilization starting to increase.

In the midstream operation most of their operation is in Western Oklahoma or Oklahoma and the Texas Panhandle. I do have two field operations in the Marcellus, one just north of [Pittsburgh] that’s growing very, very rapidly. The operator is still very aggressively drilling wells in that area. We have expanded it; I think this is our third expansion on that project, just in the last 12 to 14 months. Never seen the like of opportunities in the midstream operation that there is today. What’s driving all of that is all the liquid rich drilling its going on by everybody. Northern Oklahoma which is an old oil field, oil gas field, we think the infrastructure there it's going to need hundreds of millions of dollars spent to build out the infrastructure to process the natural gas. It's just never been setup to handle the kind of volumes that the wells at this are drilling is going to provide to the industry.

In terms of our budget before 2011 on the midstream was 80 million, this year we will spend about 170 million. I’d expect 2013 probably to be in the 100 to $120 million range. So, looks like growth is going to continue most of the growth next year will be in enhancements upgrades to the existing facilities rather than new projects. And of course with all of that main investments you can see the growth and the volumes both at the natural gas gathered volumes which is your dry gas and the liquid production from the process gas grow very dramatically over the last several years and for the first nine months of this year.

That’s brings to the financials and David will come up and go through those.

David Merrill

Thank you, Larry. Larry walked you through the company on the operational side; we had some very good results consistent growth story, some very significant things that went on in 2012 and so now I want to show you what the balance sheet looks like. How discipline that we be and how well positioned are we for things that came up down the road.

Our balance sheet at the end of the third quarter, we had $645 million of long-term debt outstanding, we had 24% debt-to-cap. So, not stretched by any stretch of the imagination. Our debt structure consists of public debt and our bank facility. As of the end of the third quarter all of the debt outstanding we had was public debt. We had nothing drawn on our bank facility. The notes that we have outstanding we had $250 million of subordinated notes outstanding as of the end of the second quarter of 2012 in conjunction with the Noble transaction. We issued 400 million dollars of subordinated note as an add-on to our $250 million tranche. We were the first time issuer in the public debt market in 2011.

Our notes mature in 2021, so there is a nice tenure associated with them. Nothing going on early. Our bank facility is an unsecured facility that’s the reason we did subordinated notes. That way we were able to leverage our borrowing base by having subordinated notes outstanding with an unsecured facility. Our borrowing base at the end of the third quarter we have already certainly been through the following determination. Our borrowing base is $800 million. I want to make sure you understand what’s in that borrowing base. The borrowing base is based on our oil and gas properties and the cash flow at the midstream business. The fleet of 127 rigs isn’t even in on our credit facility at all. So, should there be a need for additional credit capacity. There is a rig side of the business if we have it or need it. We just don't need it, so why complicate things. We have an elective commitment on the facility of $500 million as I have mentioned nothing drawn and the facility matures in 2016.

Just to give you an idea of where we sit from a metrics or credit statistic standpoint. Our leverage ratio is one time, our covenant allow it to be as much as four times. The leverage ratio that’s shown there is at pro forma for the cash flow after the Noble properties that we acquired. So, if you pro forma the EBITDA from the Noble properties, that would be about 0.8 times. Our coverage ratio is about 26 times and as I have mentioned before our debt-to-cap is 24%.

The ratings that we have from all three rating agencies Moody’s as Ba3 on the corporate side and B2 on the sub note side. Both S&P and Fitch had us as a corporate rating of BB and notes are at BB minus.

Complementing our balance sheet of the hedges that we had in place. Our objective going into any production areas, we like to be somewhere in the 50 to 70% hedged on the crude and natural gas side if the opportunity get us to that point. For 2012 we were certainly there on the crude side, we didn’t get there on the natural gas side, but for 2013 we are in that range already for 2013 on crude and natural gas.

A slide here is depicting no prices by the bar graph but the volumes that we have in place for the perspective years. We don't have any hedges in place yet for 2014. We will be looking at that and later on as opportunities do present them at prices that we would like to walk in.

To give you an idea of how these segments contributes to our revenue into our EBITDA. On the revenue side for the first nine months of 2012 our revenues were $980 million. That was up 14% from the first nine months of 2011. Revenues 43% came from our drilling business, 41% from the E&P business and 16% from the midstream business. EBITDA for the first nine months of 2012 was $492 million that’s the 12% increase over the first nine months of ’11. And 57% of our EBITDA came from the E&P side of the business; 39% from contract drilling and 4% from midstream.

Our adjusted earnings per share for the first nine months is up 5% from the year before and our capital is going to be about $800 million a little less for 2012, while going through the process of finishing up 2013 budget process that’s not done yet, but directionally where we ought to be where we think we will be is relatively close to within our anticipated cash flows for 2013. So, the opportunities clearly shows you that we are going to be executing on in 2013 essentially within our anticipated cash flows for 2013.

And with that (inaudible) I don't know if we have time for any questions.

Unidentified Analyst

No time for questions, so we certainly thank you guys for coming down and thanks for the presentation.

Larry Pinkston

Thank you very much.

Question-and-Answer Session

[question-and-answer session not available]

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