Jimmy Nguyen – Bank of America Merrill Lynch
Jimmy Nguyen and on behalf of Bank of America Merrill Lynch. I would like to thank you all for joining us today. One quick with just one note, the keynote addressed by Nick Saban Head Football Coach of University of Alabama scheduled to start at 4 o’clock today in Hudson Theatre which is on the ground floor through the lobby on the 44th street’s side of the building, there will also be a Cocktail Reception following the keynote address. So next up, I’d like to introduce Unit Corporation and with the company we Michael Earl, Vice President, Investor Relations, and David Merrill, Treasurer and Chief Financial Officer. Please go ahead.
David T. Merrill
Thank you, Jimmy. I don’t know how you follow Nick Saban being after this presentation. I’m a Big 12 Conference fan and if I can stretch this out for a couple of hours, to keep the theory here, from going here and as we speak, I’m going to try my best. I don’t know, if we have a presentation handy, all right, if not, I can talk without the slides. All right, here we’re. I appreciate you coming to hear the Unit story, Unit Corporation, we’re a diversified energy company, we have three business segments, we have an E&P segment, a contract drilling segment and a midstream segment and we believe all three segments principally has been advantageous position to where we have the ability to direct capital to where the rates of return are best.
We are celebrating our 50th year this year, so I don’t think you’ll find too many E&P companies that are on the small to midcap size and had been around 50 years, so we proud ourselves in being around this long and having seen a lot of different cycles that had pointed into a lot of different directions.
Having these three segments is an advantage in our minds to be able to grow the company. And over the last 10 years, we’ve certainly seen a lot of consistent growth in our three segments. On our E&P segment over the last 10 years we’ve averaged 212% production replacement, since 2009 when we started focusing on liquids rich areas, we’ve grown our production on the liquids side 130%, we ended 2012 with a 150 million barrels of oil equivalent. On the contract drilling side, over the last 10 years we’ve grown our rig fleets by 69%, we ended 2012 with a 127 rigs all the way in rigs, everything we do is on land and onshore.
Our midstream segment which we entered into 2004 has seen significant growth in the process in liquids sold volumes. We ended 2012 with a little over 1,300 miles of pipeline. And after this period, we have a very strong balance sheet I think it’s something that’s probably noticed in the high yield marker as we had the leverage conference which is focused audience for the Unit story.
One of our strength as I mentioned is our ability to allocate capital to where the areas that make most sense, we have specific hurdles that we’re looking for, we have more detailed criteria that going into it, but at the high level on the E&P side, we are looking for a minimum of a 15% risk adjusted rate of return on the land rig side, what we are looking for is as we build brand new rigs, we won a minimum of three year contract, in certain cases, we made expectations for two year contracts like in the Bakken, where we felt a little stronger about the strength of crude prices, but we are looking forward to cash-on-cash payout, during the initial term on the contract for that rig, at the day rate we enter into at that point in time. We use the same methodology, where ever we refurbishing and upgrading rigs, we won a minimum contract that at the end of the contract, we paid for the capital that we’ve invested in upgrading that rig.
So at that end of the day, if the operator doesn’t keep that rig we have a rig that’s more marketable than we initially putting to capital. But on the midstream segment, what we are looking for as we like to have throughput agreements or in the absence of throughput agreements we would like significant acreage dedications as we put in plant for a commodity exposure based type contract which is a PLP, or a PLI contract, we are looking for a minimum of a 25% risk adjusted rate of return and for fee based projects, which have a little more stability to own little less risk, we won 15% risk adjusted rate of return.
Starting with the E&P side of the business, as I mentioned in early 2009, we made a strategic decision to focus more or so on liquids rich areas, we are not unique in that area, but we started back in 2009. In 2008 our average, our production, our liquids production averaged 25% of our production stream and currently, we are a little over 40% of liquids being in our production stream, so very significant change. Our key areas that we’re focused on is four, we have a Granite Wash primarily in the Texas Panhandle, our Marmaton play it’s an oil play in the Oklahoma Panhandle. We have a Wilcox play that’s in Southeast Texas and our Mississippian play which is our newest endeavor we’re primarily on the Kansas side of the Mississippian play. Our reserves as I mentioned we are a 150 million Boe at the end of the year and we were 62% natural gas and oil reserve and 79% prove developed.
Our objectives each and every year is to replace at least a 150% of each years production with new reserves, roughly down over the past 29 years, on the E&P side we’ve averaged 222% production replacement, last year alone we averaged 337% production. I don’t think you’ll find another E&P company that’s one, see that have been around 29 years and two that we’ve been achieve our 150% production replacement each and every year during those 29 years.
Our production for 2012 was up 18% a year-over-year at 39,000 Boe a day, more importantly in 2012, our liquids production increased 28% year-over-year and the year before about liquids production increased 55% year-over-year, so we’re on a pretty trajectory and what I also want to point out is we’re, it’s not that we’re ignoring natural gas at all, obviously there’s subsequent natural gas in the liquids areas that we’ve had a portfolio of properties on our balance sheet that allow us to go to where the returns are and where the best economic are. So most of our properties are held by production that gives us the luxury of pursuing where the economics are which today are on the liquids rich areas and then who knows what the next year or two, five, 10 years brings, we could certainly shift toward a different focus toward natural gas, if that’s where the primary economics reside.
Our guidance for 2013 is somewhere between 44,000 and 45,000 Boe a day and to just touch on a few of our core plays, first one I want to touch on is the Granite Wash, primarily focused in the Texas Panhandle. We have about 47,000 net acres there, back in the last part of 2012 we did an acquisition, we’ve acquired some level of properties, a good portion of which was in the Granite Wash, and so we ended up with 47,000 net acres in the Granite Wash when you combine that. But most of our acreage are held by production, and we have about 800 potential drilling locations in the Granite Wash. We believe that’s a very conservative estimate.
There is about nine different producing sands in the Granite Wash, we are producing currently out of eight those nine, and hopefully before long it will be nine, typical wells in Granite Wash is costing about $5.3 million, the EURs is around 3.5 to 4 Bcfe, about 46% of the production stream is liquids, using $90 oil, $30 NGL and $3.25 natural gas, the rates of return are here in the 50% to 70% range.
Let’s see, in the second, first in the year we had two rigs running in the area, we increased that by two more during the first quarter, so had four rigs running, so we had to add a fifth in the third quarter, and we may potentially have sixth rigs in the fourth quarter. It’s definitely a core focus area for us.
We will spend about a $140 million of capital out here in 2013.
Moving on to the Marmaton play, again it’s a oil play in the Oklahoma Panhandle, it’s relatively shallow about 4,000 foot vertical, we have about 113,000 net acres here, we have about 150 locations using 640 acres spacing as assumption, oil costs out here about $2.7 million each, EURs are about a 120,000 to 130,000 Boe that’s 92% liquids it’s primarily oil, so most all of those liquids are oil.
Let’s see, we had two rigs running out here and we spend about $90 million in the mid in the Marmaton. Wilcox play it’s a play in Southeast Texas, it’s the area where we had a first discovery in 2003, since that time we drilled quite a few wells it’s an area that’s not [succeed] from the buy side on the equity perspective, it’s a conventional play so we’re drilling vertical wells out here, we have to drill off of 3D, it’s very salted area, so you have to be very specific to where you’re drilling, but one of the very interesting things is that from the 10 years that we’ve been out here, last year we came across an area we call it the Gilly field, that’s the discovery that we made in a lower, it’s in upper lower Wilcox.
Prior to this we’ve been drilling to the at the middle Wilcox, but this is in the upper lower Wilcox, our geologists had noticed the marker off of the 3D that was in that area that was deeper than that we had been focused, we drilled out here and came across this discovery and are very, very excited about it, it’s about a 1000 acre structure area, so relatively small reservoir area, contains about 260 Bcfe gross reserves about 170 Bcfe net to us, so very, very significant and a very small area.
There is about eight different producing sands, we’ve drilled to four, we’ve drilled through four of those, what you have to do out here since they are vertical wells, you start in the deeper sands, you perforate in furrow and as you to point some of that area you move up to the next level of perfs and flow and you just keep going. What we, it’s very interesting we just talked about in our first quarter call, that about a mile north of the Gilly field we have come across another discovery and we’re not to a point yet, but we can quantify it, we’ve drilled two wells in the area and are very, very excited about it. This mark through that we saw that help led us to the Gilly field, we haven’t been looking for it across all the acreage that we’ve been drilling for the past 10 years. So now we’re able to go back overall that acreage and look for that marker and we are very optimistic there maybe other opportunities like that.
Again, the equity side doesn’t really consider this too sexy just because you cant take a number of acres, time spacing and come up a resource play metric, but the bottom line is it has a very, very significant economic benefit to Unit as a whole. And so whether the equity side gives us credit for it or whether they don’t, the cash flow is coming and we’ll be able to put that cash flow to work for our shareholders.
The wells out here costs about $5.4 million to drill and we’ll spend about $60 million out in the Wilcox 2013. Our newest endeavor Mississippian, I know there is a lot of buzz about the Mississippian and as it is in most plays, not all acreage in particular play is the same, different areas produce different results, we’re focused on the Kansas side, we’re in central Kansas, primarily in Reno County we have about a 110,000 net acres, we have about 300 potential drilling locations, using 320 acre spacing, the wells out here cost, about $3 million to drill, we have only drilled four wells so far. So we believe we’ll be able to get those costs down to around $2.5 million each, the reserves we believe are in a range between 120 million to 180,000 barrels of oil equivalent. Rates of return using our same economics that are, our same assumptions that I was telling you about are in the 40% to 70% range.
We have rating on infrastructure now we drilled, as I mentioned we drilled four wells out here, we have drilled three additional wells during the first quarter, those wells are waiting on completion, we are waiting on pipeline and processing plant to be installed, that should be completed by the early part of the third quarter, we ought to know something about how that projects coming along because our midstream company is putting in that infrastructure. So we have the ability to know who to talk to, if we need a better understanding of what the timeline looks like, but we are very excited about it, our midstream company will certainly be gathering and processing the production that our E&P company has out here and there are other third party operators that our midstream company we will be processing for as well.
We will spend about $40 million in the Mississippian play, and since we are waiting on infrastructure to come in, we don’t have a rig running right now, but in the third quarter we plan on bringing the rig back, start our drilling operations again and hopefully get up to two rigs by the end of the year.
Moving on to the contract drilling segments, we have 127 rigs in the fleet, during over the past two years we’ve refurbished or upgrade 34 rigs in the fleet. In 2012 we added two new build rigs to our fleet and in 2013 we plan on adding one additional new build rig, which I will talk about in a little more detail later.
Day rates and margins, our tale of two stories between, in 2011 day rates and margins were both up about a $1100 a day, in 2011 day rates started at the beginning ‘11 and were rising throughout 2011 in 2012, they started high and started working our way down a light bit from Q4 of ‘12 to Q1 of ‘13. Day rates changed about $250, we’re not seeing much change in day rates or margins, on the short-term we believe things will kind of hold steady for a while. We had 66 rigs running on average for the first quarter 2013 and that’s up 64 rigs running in the fourth quarter 2012.
Our rig fleet is concentrated into 750 to 2000 horsepower rig category, both of the rigs that are in the most demand today by operators drilling, the [ real shallower] rigs the smallest in 750 horsepower rigs and now it’s greater than 2000 horsepower rigs are ones, they have made a lot of money overtime, right now they are not working in those rigs that run primarily in dry gas areas and given process that we have today, there is noting really going on much with those rigs.
If we had an opportunity to sell some of those rigs, we would certainly do that and redeploy those proceeds in the focal point of our fleet. As I mentioned, this year we’re adding this one new build rig, our plans are to build a 1500 horsepower AC rig, it’s the first AC rig that we’re having on a fleet, we’re very excited about it, it’s a prototype rig, the construction is going on as we speak, it ought to be complete by the third quarter or early fourth quarter, the benefit of the rig is it will be a rig that works on multi pad wells primarily, it will move relatively quickly and very efficiently, it will take less loads to move from location to location and there will be less permitting issues, so it will be easier to move it along the highways and back roads. Also it will have a very efficient mud handling system and fluid handling system, so to be, great benefit for the horizontal drilling activity that goes on now.
The rig will initially got to work for our E&P company, since it’s a new design a new prototype rig, we want to get, we want to get the dust and the cobweb all blown out, are not using our E&P company to get it worked out before we start developing it for third-party operators. Turning now to our midstream company, our midstream company our operations are focused in the Mid Continent and in the Marcellus, in the Mid Continent we’re primarily in Oklahoma and in the Texas Panhandle, in the Marcellus we have operation just North of Pittsburgh and we have an operation that’s in Northern West Virginia.
There are tremendous amount of opportunities in the midstream side of the business, you see right now there is a lot of infrastructure opportunities, our midstream company is a C-Corp capital structure, not an MLP. One of the advantages that we have is that we have the ability to do a grass routes organic projects MLPs have a light more of a challenge in doing those kind of a Greenfield projects, they are certainly needing immediate cash flow for the distributions that they maintain. We have the ability to put some capital to work, incubate those and grow value for our overall company.
Volumes have just grown very, very nicely both on the gathered side and on the processing in liquids sold side, we have had some negative things going on, fairly recently on the liquids side, as most people not sure aware of what’s going on in the NGL side impacting us in the fourth quarter and in the first quarter have been certainly first and foremost up midstream company’s operating in ethane rejection mode, given pricing that we have on ethane and then there have been several weather related issues freeze-off and those types of things that impacted us during the first quarter on the midstream side of business, but again, there is just a tremendous amount of opportunity, a lot of potential growth here in the midstream side of our business.
Some of our focus projects this year first half is in the Mississippian, Reno County I alluded to this earlier when I was talking about the new build rig in the E&P side, we’re adding at almost a $30 million a day processing plants in the Mississippian that project again it will be ready in the third quarter, we hope also in the Mississippian on the Oklahoma side, our Bellmon plant, the first plant that we had operational in the Mississippian that plant went live in the first quarter, we’re already in the throes of increasing the capacity of the plant, given the development of third-party operator is doing out there, this particular plant doesn’t have any unit production going through it, it’s all a third-party plant and we’re adding a 60 million a day processing plant to this Bellmon system, hopefully, it will be done by the end of the year.
We’re also doing some expansion of our first phase that we did in Pittsburgh mills area, just north of Pittsburgh, we’re doing a phase II expansion there and we’re very excited about what the operator is doing up there and their growth plans. Now turning to the balance sheet, again the company is growing very, very nicely and while we’ve grown very nicely, we’ve also been able to maintain a very strong balance sheet so again we attribute that to the mix of having the three business together. At the end of the first quarter, we had long-term debt of $750 million, we had a debt-to-cap ratio 26%. How that debt breaks out is we have public debt, we have bonds $650 million worth of bonds and we have our bank facility, in 2011, we were a first time high yield debt issuer. Unit had prior to that time only used bank facility debt, so we did a $250 million issue in 2011, last year along with the Noble acquisition, as partial financing of the Noble transaction, we issued another $400 million of bonds it was an add on to our $250 million issue that we had, the bonds are 10 year, bonds and are due in 2021.
Our bonds are subordinated and the reason they are subordinated is because our bank facility is unsecured, we are a unique company in that most companies our size do not have unsecured bank facility that’s usually reserve for investment-grade entities, but because of our bank facility being unsecured that’s why we have the subordinated notes.
Our bank facility has $800 million of borrowing base. We’ve elected to have $500 million available to us. And we only have $70 million outstanding at the end of the first quarter. I do want to point out that our borrowing base is only inclusive of our oil and gas properties and the cash flow from the midstream company, our fleet of a 127 rigs isn’t even in our credit facility. So now that we need $800 million of additional borrowing capacity, but we have the rigs on top of the $800 million should we had a need for capital a lot of dry powder.
Our credit statistics again looks very nice, in my opinion anyway. Our leverage ratio is 1.1 times that’s after doing the Noble transaction, it ought to continue to come down a little bit and our coverage ratio is 16 times, the metrics that we show here or debt to our proved reserves and to our proved developed reserves that’s assuming 100% of debt and attributable to the E&P company that’s a very, very conservative assumption, if you just allocate $250 million to the other two businesses that leave $400 million on the E&P company that brings those ratios down 30% to 35% from what you see there.
And don’t anticipate you capturing all this, but the credit metrics you can see it historically Unit has been a very, very conservative refinanced company, we’re not afraid to use our balance sheet for the right opportunity, we will that’s why the things you see on 2012 they certainly jump out at you as changes from what you see in the years priors to that. But again, you’ve got to keep it in the context, our coverage ratio after doing the largest acquisition that the Company has done in its history a $600 million deal, our coverage ratio, our interest rates, our leverage ratio I’ll get right one of those ratio.
Our leverage ratio is 1.1 times, so we’re very proud of how we have been able to manage the balance sheet and we’re very glad that we have the ability to put capital to work when the right comes along. The markets are very hot and rates are very nice for high yield debt as you all are well aware of we will remind disciplined as we look at acquisition opportunities we’re not going to change our criteria for evaluating transactions if a transaction is a good transaction we’ll find a way to finance that whether it’s a transactions that happens today or whether it happens five years down the road.
Complementing our balance sheet are the hedges that we have in place. Our philosophy on hedging is as we like to enter into any production year with somewhere around 50% to 70% of our crude oil and natural gas hedged, for 2013, we’d certainly achieve that we’re about 80% hedged on the crude side, for our anticipated 2013 production we’re about 70% hedged on the natural gas side. We have started layering in hedges on 2014 as we see opportunities to do so. We are not at the levels that we target for entering into a production year, but we are not there yet. Revenues for the company in 2012 were $1.3 billion, for the first quarter of 2013 revenues were $319 million, 48% of our revenues came from the E&P segment, 34% from contract drilling and 18% from the midstream side.
Our adjusted EBITDA for the 2012 year was $657 million, a $148 million for the first quarter of 2013, 70% of our EBITDA came from the E&P business, 28% from the contract drilling business and 5% from midstream. Our budgeted capital for 2013 is $789 million excluding acquisitions we’ll evaluate those on their own merits whey they come up, $586 million of the $789 million is on the E&P side, so the lion share of our capital is going to our E&P company, $105 million on the midstream side of the business, and $98 million on the contract drilling side, the way we have budgeted our capital funding for this year is it should be within our anticipated cash flow and some non-core assets sales.
So we should end up the up the year pretty much covering our CapEx with those types of funding sources. And that’s all I had prepared to share with you regarding Unit, if there are any questions I will be happy to entertain those.
Hi, I don’t know the company well, so is that the plan to just maintain these three divisions with a similar kind of focus going forward?
David T. Merrill
As I mentioned, it’s a great way to continue to grow the business, we’re able to take the initiatives where our contract drilling business is generating a lot of free cash flow, we can make, if the returns are there if it makes sense, we can make that money available to our other two businesses and they can outspend their internal cash flow and we still have maintained the balance sheet that we don’t have to fund through debt or equity raises. But if we do our jobs right, we keep growing the company, it’s going to be a time when we need to separate the businesses, separate the E&P business from the contract drilling business or the midstream business there is several different options for the midstream business one of which I’m sure is not at the forefront of anybody’s mind in here until we’re doing a potential MLP, we are not in need of capital for doing an MLP, but it certainly would be a vehicle to help with valuation, if you put a pure play valuation on our midstream that we don’t see in the diversified structure that we had today.
The rig side of the business what was probably be a catalyst for the rig side of the business to be separated would be, if we did another Noble size type acquisition, another one or two of those and what you end up with as an E&P company that so far overshadows the contract drilling business so it kind of loses its identity within the corporation, a fleet of a 127 rigs is a very meaningful business and at that point we would probably need to be separated out and traded as an independent company.
Hi, could you talk a little bit about some of the value drivers or other fundamental metrics that you might look at to decide on how you allocate capital either within, both within E&P and then between E&P, contract drilling and midstream?
David T. Merrill
Sure. As I talked a little bit about some of the minimum metrics that we’re looking for a decision to drill a well, we’re using $90 of oil $3.25 natural gas to decide whether we’re going to drill a well or not and what we expect to get as we want our money back 2 for 1, those are some of the additional metrics that we’re looking forward, in addition to just minimum rate of return, similarly, we’re only looking for the same thing on the mistream side of the business and the midstream side of the business for a fee-based project we want cash-on-cash money back within at least four years and on a percent of proceeds type contract we’d want back in within at least six years.
And I guess one of the things that I’m interested in, as well as how, when you make shift between the day that you might be pushing the portfolio towards oil to saying okay, well the oil days are over let’s move back towards gas, or let’s move to one of the other segments and how do you think about that is it all within the framework that you laid out or are there other things that you’re looking at as well?
David T. Merrill
No, that would be primarily, of course, there’s going to be other factors, but what we would be in order for us to change focus from where we are today, saying there was a higher interest in potentially going toward dry gas, there would have to be the forward curve would have to show that it’s more than just a short-term blip, if that strip is above $5, $6 for a year or two out then that gets you thinking about where you want to direct your capital because you can’t just turn the ship on a dime, it takes a quite of bit of time to change your shift from the wells you are drilling and focused on today to focusing on something completely different.
Thank you, very much. That’s an interesting perspective.
David T. Merrill
Thank you. I appreciate it.
Jimmy Nguyen – Bank of America Merrill Lynch
Okay, that looks like that's all the time we have for questions. Just want to thank everyone for coming, and thank you, David and Michael, for joining us today and for sharing your story.
David T. Merrill
Thank you, very much.
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