Angie Sedita - UBS
Alright. We are very pleased to have Unit Corporation as our final presenter of the day and speaking here will first be Larry Pinkston CEO of Unit Corporation. Larry joined the company in 1981. He held a number of senior positions over the years and was named Vice President and CFO in 1989.
In 2004, he was elected to the position of COO and became Chief Executive Officer in 2005. We’re also pleased to have David Merrill here who is also the CFO, a position to he was named to in 2004.
Thanks Angie. We really appreciate you all staying around to hear our story. We think we have a very exciting story. It’s unique and we’re involved into three different segments of the energy industry. All segments and all of them we’ve been involved in since 2004, of course we got our start as a drilling company back in 1963, really got in to the exploration business in the late 70s and in the midstream business in 2004. They’ve all three shown very consistent growth over the years, very consistent economic growth. We finished the year of 2011 with 127 drilling rigs, 116 medium barrels of oil equivalent and a midstream company that had little over 900 miles of pipeline and 11 processing plants now.
We’ve always considered one of our major strengths is our corporate structure. What it does is it enables us to direct our investments in to whichever segment in the industry that we feel like has the best rate of return for our shareholders and those cycles are very seldom ever the same. We went through a very aggressive rig building cycle for three or four years. This year has dropped off about nearly as aggressive, but we’re seeing pickup this year has been the opportunities in the midstream segment.
There are bigger opportunity, larger opportunities right now in that segment that we’ve ever seen since we've been in the midstream segment and certainly bigger and even bigger than all of the group that runs our midstream company has ever seen in their lifetime with all the processing infrastructure that’s going in right now.
Our more consistent year in year out growth has always been our E&P segment, that’s been the segment that we can somewhat control our growth, we create our own opportunities in that segment. Whereas the other two segments are driven by opportunities by drilling oils that those two segments can’t control. But the three mix, the three work very well together, we’ve directed investments from one subsidiary to other subsidiaries very aggressively over the last 10 years, over the last 20 years, but all three segments they’ve show very good, very consistent, very nice growth over the time period that we’ve been involved with in our drilling segment, our rig fleet in the last 10 years has increased to about 69% and our E&P segment we’ve averaged replacing a 195% of our annual production with new reserves over that 10-year span and since 2004 since we brought 100% of the midstream company. We've seen over 260% increase in the amount of natural gas that they process, over 600% increase on the amount of the natural gas liquids that they've sold, a very dramatic growth in that segment.
In our E&P segment, as I mentioned, we finished the year at 116 million barrels of oil equivalent reserves, that was up 12% over 2010, 81% of our reserves are prove developed. It's not that we don’t have more [PUDs] or you definitely have more PUDs. It’s always been our philosophy our strategy to always keep our PUDs we have booked pretty consistent year to year as a percentage of our total reserves. So basically whatever PUDs we drill each year, we replace with new PUDs and our relationship has been about 80% as long as I could remember.
We are -- currently about 36% of our reserves are liquids, so dramatically over the last two or three years in 2009, we made a decision early in 2009 to change our strategy from being previously almost entirely driven by the natural gas opportunities to looking for liquids. Our three key areas that we are aggressively drilling in today, one of them is Granite Wash in the Texas Panhandle which has been a legacy acreage position that we had for 20 plus years. The Marmaton which is a old play in the Oklahoma Panhandle in Beaver county and the Wilcox play in Southeast Texas which is a conventional play driven by 3D seismic different type play than the other two. But the economic year in and year out have competed very favorably with our other two plates.
Our goals as I mentioned or I think mentioned each and every year is to replace at least a 150% of our annual production with new reserves. We have done that every year for the last 28 years. I don’t know that there is another company that has presented at this conference or probably any other conference, but you can say that they have had that kind of consistent track record over that longer period of time. Our average production replacement over those 28 years has been 218%. Last year we replaced 202% of our production with new reserves. The way we have been able to do that consistently over the years is we don’t depend on acquisitions for our growth.
We have a exploration staff that develops prospects, that we drill prospects, that is our core growth. So we begin each year with the budget, with a game plan of replacing what we are going to need to do, what kind of capital we need to invest to meet our minimum goal, and then we add to that as the year goes on. Of course (inaudible) as to which players are working, which players aren't working, but our drilling program has been the key avenue that has enabled us to be such a consistent growing company over that period of years.
Last year was a tremendous year for us in growing our production. We produced about 33,000 barrels of oil equivalent for the year which was up 23% over 2010. As you can see the very dramatic increase in the amount of liquids production, about 55% increase in liquids from year to year has been growing basically from 2009. Our guidance this year is, we'll produce somewhere in the range of 36,000 to 37,000 barrels of oil equivalent this year which will be up in the range of 9% to 12%.
Our first quarter production this year was about 36,000 barrels of oil equivalent which was up about 2% over the fourth quarter of last year and up 18% or so over the first quarter of last year. As to how we've been doing our liquids in 2011, about 39% of our total production was liquids, that's up from 27% of our total production in 2009 and it has been a situation where our percentage of liquids is going up because our natural gas production has been going down. From the last slide you saw that our gas production actually in 2011 was up 8% and over 2010 that's not a result of drilling in dry gas areas.
The gas increased production was residue gas, the gas that we processed so it's not a situation where a gas production is going down and our liquids I mean the growth production strangely going up. Our guidance this year on the liquids will be somewhere in the 42% range of total production and I always ask what's our mix that we would like to have? And there's not one, I would like to have a 100% liquid drive down but as long as the disparity exists between oil and natural gas prices today, we will continue to focus on liquids and if we get up to 60% of our stream is liquids production before the economics changed or we can go back to drilling gas as we will be.
As far as our core plays sort of the Granite Wash play we have about 21,000 acres currently in the play. Most of our high interest acreage is in Hemphill and Roberts County and the Texas Panhandle as I mentioned earlier, that's been a legacy acreage position that we've been drilling oils for the Morrow wells or Douglas wells or that we've been drilling wells in the Texas Panhandle for 25 years.
So it was a position where we didn't have to spend a lot of money had to obtain acreage to drill wells to the Granite Wash. We went through a couple of years of drilling vertical Granite Wash wells before it really the technology existed mainly the fracking technology existed to drill the horizontal wells, had good results on the vertical wells but the results we are seeing today on the horizontal wells are lastly beyond anything that we've seen in the Texas Panhandle over the last 20 plus years, just an area that just keeps giving and giving.
Last year, we drilled 16 wells, had 30 day [IP] rates of about $6.8 million per day. The production is about 50% liquids. Our mid-stream company process is 90% plus of the liquids. So, we’re benefiting from the total uptick from the liquids of not only producing them but also processing them, of course, our rigs are one of the biggest rig companies in Texas and on our rigs drill, all the wells that we drill in the area we ran three to four rigs, all of last year. That’s our plan this year is to continue three to four rigs. We plan on drilling about 20 wells this year. Wells, last year average costing, about $5.5 million per well. Average reserves that we booked were about 4.6 Bcf equivalents. Again, it was about 50% liquids.
We have seen recently a reduction of our drilling times in the field, mostly from new technology that has come along to drill through the curve, but what was, it was always taking 40 to 45 days from (inaudible) to TD. And we drilled a few wells now in the 30 day range. So that could be a nice add-on to the economics in the well we manned up being able to drill more than 20 wells this year, if we continue to drill on this fastest as we are now.
But we know that over. We drilled a couple of three more it will (inaudible) it wouldn’t just aberrations. It was something that we can plan on going forward. But to Granite Wash, the economics of the Granite Wash would compete with any economics of any field that are out there. Our results I know some companies has some very wide results, some real good wells, some very poor wells our results are getting much more consistent. We’ve now develop seven different sands in the Granite Wash, most of the wells have been in the A and B zone, but we have developed always through, almost the last oil we drilled. Some are those are a little older than the others but overall the production characteristics are very similar.
In the Marmaton which for us somewhat new area, our first well we drilled in the Marmaton was two years ago I guess now it’s a shallow oil play. We have currently about 102,000 acreages now in the Marmaton. The wells are about 6500 vertical depths, 4500 foot laterals.
Wells cost about $2.7 million to drill, we can drill them in about 13-14 days, now the well cost about $2.7 million to drill with a 4500 for laterals, the 30 day fee rates thus so far averaged about 308 barrels per day, its 92% liquids, about 85% or so that is oil. We drilled our first extended lateral 9500 foot lateral.
It is in the testing stage, the cost of that well is about $4.2 million. So we are getting basically two wells $4.2 million versus two shorter laterals that would cost us $5.4 million. Again, it's still in the testing stage. We are now over the next, its been producing now for about 15 days we will know over the next 15 or 20 days kind of what the results are going to be but we’ve not seen anything yet that is disappointed it is not all the acreage we are going to be able to drill with the extended laterals but it would change a lot of drilling programs I guess, probably in the majority of the acreage drilling extended laterals instead of the shorter ones.
So that’s a pretty good asset side, we have been able to add in the neighborhood of 5,000 to 6,000 additional acreage per quarter for the last couple of quarters. I think we will probably be in the neighborhood of 4,000 to 5,000 acres for the next couple of quarters of [added] acreage. As we have got two rigs drilling in the field right now, we are always asked why don’t you put more rigs into the field. It might be because we haven’t decided yet what is the best program going forward.
And with that six rigs in the field last year then that would have minimized the opportunities we have today of drilling the extended laterals. So until we are really comfortable with the drilling program, we got comfortable with the completion program now and we noted down to the best way to complete them so as soon as we decide on the extended lateral program, you will have a better idea how is the best way to drill them.
So we will be drilling in this area for years and years and years and we almost increasing our acreage position by the amount of acreage that we are drilling each year. So a lot of that prospect just continues. I forgot to mention I knew there was something else on the Granite Wash, a year end we had identified about 240 locations across our acreage block that are still undrilled, about 90 of those you could book today as proved reserves, rebuy that were close to coming had that much booked in our current reserve report, about a 90 of them could be booked as proved and developed, the other 150 would be probable and known reason they are not proved is because they don't have all set production that you can classify them as proved.
But with running, with drilling 20 to 25 wells a year again you see there's a 10 year inventory life just on the locations on the inventory on acreage we have now. We are adding to this acreage last year, we replaced acreage that we drilled on. This year I think we could have an opportunity (inaudible) even doing more than that. And Wilcox again is our conventional play. It's driven by 3D seismic. It's driven by structures, small structures that we find across the field, the structures could be anywhere from 200 acres to 1200 to 1500 acres. It's just when you find one of these structures they are filled with oil and gas.
We currently have 20 some thousand acres, 27,000 net acres out in the field. We sign options in the fourth quarter of last year for over, it covers over almost 130,000 additional acres by no means, well all of that 130,000 acres be productive but we will not lease nearly the 130,000 acres but it gives us 130,000 additional acres that is 3D seismic across all of that acreage block.
So we are in a process now of identifying the acreage that we want to lease on. And we have until the end of the year to make that decision and of course there are opportunities to extend it another year better option than we have right now to look far at the end of this year to identify the area that we want to lease. Very exciting area for us, the production here is again about 50% liquids. Our results last year of the 17 wells that we drilled, the daily production was about almost 250 barrels of oil equivalent a day reserves of about 230,000 barrels of oil equivalent; again, about 50% liquids. We plan on drilling 15 wells this year. We're dropping back some because we're spending the majority of our time looking over the option acreage this year as to areas that we want to lease.
Bakken, we're a non-operator in the Bakken. We have about 13,000 acres. Angie says I need to speed up here. The wells are getting very consistent. We'll drill about 20 wells this year. Spend about $30 million in the field. We're the last one, so there won't be anybody waiting on us. Our budget this year in E&P is $485 million -- $457 million. $385 million of that will go into actual drilling costs.
The rig side, we have 127 rigs. We've sold one rig in the first quarter. We added a new 1,500 horsepower rig, went into the Pinedale in the first quarter. We have one additional rig today, new rig, to add into the Bakken that will go out this quarter. Beyond that, we have no contracts to deliver anymore additional new rigs. And I don't really think the possibility is too strong that we will be doing that.
Rig utilization, last year we averaged 76 rigs. This year, first quarter was 81 rigs. Second quarter is going to drop down some. We're still seeing a big shuffle going on in the rig fleets between dry gas and liquids. And even some shuffling in some of the liquid plays. Some operators are getting more aggressive.
Some operators are dropping some rigs. So I think we'll be shuffling around rigs probably for the next two quarters. I think once the storage season is over, depending on what gas prices do, we could see a possibility of a pick-up in some of the gas drilling, but we're not expecting that to be monumental.
Utilization, of course, the highest utilization is in our 1,200 to 2,000 horsepower rigs. The shallower horizontal drilling is going on now. It's creating a pretty good demand for our shallower rigs. The Mississippian play is a play that's going to need a lot of these rigs of the industry to go to work to drill, to save the acreage positions that have been put together up there.
We know we're close to having enough rigs as an industry up there to save the acreage that's been leased. Day rates and margins; day rates, the first quarter of this year (inaudible), which was about $1,000 a day higher than what our average was last year.
Day rates have been pretty consistent. Other than putting different sizes of equipment to work, 1,500 horsepower rigs coming down and the 1,000 horsepower rigs going to work, we're not seeing any pressure for day rates to come down on those rigs. At the end of the first quarter we had three rigs that were drilling in dry gas areas. Today we have no rigs drilling in dry gas areas.
Midstream; as I mentioned, all kinds of opportunity today in the midstream. Our budget last year was $80 million for the year. Our budget this year for the midstream is $220 million. Again, it's almost all driven by processing activities in western Oklahoma, Texas panhandle. Kansas, I don't see really a slowdown in that area for several years, as long as this play keeps developing.
A little history on the volumes; dry gas volumes have been driven by a project that we have in the Marcellus. And of course, the processing volumes are in western Oklahoma and here. Do we have time for David to speak?
Angie Sedita - UBS
We'll keep it brief. Just to give you a snapshot of things on the financial side since Larry walked you through how well things have worked on the operating side. We have a very strong balance sheet. We ended the first quarter with about $38 million of working capital. We had long-term debt of $316 million at 14% debt-to-cap. Not very levered by the stretching imagination.
We're very disciplined on how we put capital to work. We certainly are looking up for our shareholders. We want great return opportunities when we put it to work. We don't let capital availability drive going out and doing acquisitions, but we love doing them. We're just going to be very disciplined on how we put that money to work.
Giving you a view of our debt structure; we have public debt, we have bonds outstanding, and we have bank facility debt. We were a first time issuer in the public bond market last year. So in the history of Unit, we finally got out there with some public debt. We issued $250 million of 10-year 6 5/8 sub notes. We also have our bank facility outstanding.
We have a $600 million borrowing base. Well certainly, everybody is behind the [spring rate] determination period. But our borrowing base is $600 million. We've elected to have a $250 million commitment available under our facility. We had $66 million outstanding under the facility. We have the ability to raise that commitment, subject to the banks approving it, of course.
But our $600 million borrowing base would indicate that that wouldn't be a difficult thing to do, should we ask for it. We just choose not to pay for the unused portion. We're very conscious on cost side, on the finances as well, as that's how we focus on cost operationally. Our facility matures in 2016, so we're in good shape there. I do want to point out that our bank facility is an unsecured facility.
That's why we did the subordinated note issue. That way we could leverage our borrowing base a little more. And our rig fleet of 127 rigs isn't even in our borrowing base. So should there be a desire or a need to have additional capital availability, we have a rig fleet of 127 that's not even in the -- we can afford anyway for the $600 million that we have available today.
On the revenue side, for 2011 we had $1.2 billion of revenues. That was a 37% increase over 2010. The first quarter of 2012, revenues were $332 million. That was a 34% increase over the first quarter of 2011. 42% of our revenue came from the E&P segment, 40% from contract drilling and 17% from midstream.
For 2011, EBITDA was $604 million. That was a 37% increase over 2010. And for the first quarter, EBITDA was $166 million, a 30% increase over the first quarter of 2011. 57% of our EBITDA came from the E&P segment, 38% from contract drilling and 5% from midstream. Earnings per share was up 32% in 2011 over 2010, and 23% Q1 '12 over Q1 '11.
We do complement our balance sheet with a hedging program. We're very straightforward on how we hedge. We drill wells, we operate rigs and we have a midstream business. We're not trying to do any financial engineering on the hedging program. Our hedges -- the direction we have from our Board is our hedges need to qualify for cash flow hedge accounting treatment.
And as you know, that limits a lot of creativity that can happen in a trading group. Our target for any production year that we enter into is we like to be somewhere in the 50% to 70% hedged for crude and natural gas. Looking at our crude side, for 2012 we're there on crude. We're almost 80% hedged for 2012 at just under $98 on average.
For crude on 2013, we're about 50% based on our anticipated 2012 production at just under $103 per barrel. On the natural gas side, we're about 40% hedged in '12 at about $5. Wish we had a whole lot more of that, and especially going out from here. And for 2013, we're about 23% at -- we'll have some swaps and collars in place in there around the $3.20 to $3.25 range.
Our capital expenditure budget for 2012 excluded any acquisitions. We'll evaluate those on their own merits as they come up. But comparing our 2012 budget to 2011, it's up. It's actually down 5% when you exclude the acquisitions that we made in 2011 at $801 million for all three of our segments combined.
By segment, $457 million is on the E&P side, $120 million on the contract drilling side. And as Larry mentioned, we had a very nice increase given opportunities in the midstream side, and that budget is $224 million. And that's our prepared remarks for Unit, and I don't know if there's time for questions or if we're done.
Larry, do you have a view on natural gas such that you'd be comfortable applying conventional gas in Oklahoma or you know some of your historical core areas?
Yeah. We made one acquisition late third quarter of last year, Arkoma Basin dry gas properties. It depends on what you pay for. We bought those properties for less than $1 an Mcf, at 55,000 net acres of [HPP] acres. They came with the acquisition that we allocated no value to, only valued the production that was incurred off the properties.
We bought them for less than $1 an Mcf. They're long-life properties. Would we be interested in something else at that level? Definitely. It all depends on what you've got to pay for. We're not going to pay $3 an Mcf for it today. But if we can buy it right, yes. Natural gas will come back. You just don't want to --
Especially anything in our core area, we know the risks. We are very comfortable with assessing the risk. As long as you don't get in a situation where you've got leasehold that you have to drill on, we're safe. We don't want to be in a position and have no guess on the timing on our acquisition. If it's [HPP] acreage, yep.
Angie Sedita - UBS
Well, we want to thank Larry and David for being here this afternoon. (inaudible)
Thank you, Angie.
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