Unit Corporation. (NYSE:UNT)
Bank of America Merrill Lynch Leveraged Finance Conference
December 1, 2011 08:50 am ET
Larry Pinkston – CEO and President
David Merrill - CFO
And next we have Unit from Tulsa, Oklahoma. And from Unit we have Larry Pinkston, who is the Chief Executive Officer and President; and David Merrill, who is the Chief Financial Officer. So, Larry, you can take it away, please.
Thank you. We thank everyone for joining us this morning. We think we have a very exciting story on the equity side and a pretty boring story on the debt side, which I – we’re kind of new to this arena and that we had our first debt offering in mid-year this year, but it’s been an exciting trip.
We are an integrated energy Company that has three distinct energy segments. We finished the year on our E&P segment with about 104 million barrels equivalent of reserves. We’ve a contract drilling segment that we currently have 126 drilling rigs. And we have a midstream segment that currently has a little over 900 miles of pipeline and processing plants and treating plants and et cetera, et cetera that goes with the midstream operation.
We really consider our strengths to be somewhat two fold. One, we think our corporate structure is a significant strength and that gives us the ability to invest into whichever segment that we feel has the best rate of return for our shareholders. And the cycles are very different. There are times when you want to add drilling rigs, there are times when you don’t want to add drilling rigs or times when you want to – when you have the ability add to the midstream operations when the opportunities are there, there are times when there is no new grass roots projects on the midstream operations, but cycles are different with any segment. The most consistent segment has been our E&P segment and that we can create our own opportunities in the E&P segment.
In our E&P segment, over the last 10 years we’ve grown our oil and gas reserves, we’ve averaged replacing 191% of our annual production with new oil and gas reserves. In our contract drilling segment in the last 10 years, we grown our rig fleet by 120%. And in the midstream segment we really consider 2004 as our genesis in the midstream segment, but since then we’ve seen our natural gas volumes that we process increased over 500%. We’re seeing natural gas liquid volumes that we sold, increased over a 1000%. And we’ve been able to achieve all this growth and maintain a very conservative balance sheet. We finished the third quarter with a 14% debt-to-capitalization ratio.
In our E&P segment, as I mentioned we finished last year with 104 million barrels equivalent reserves, we’re 80% proved developed and we’re not an aggressive [book to] reserves. And we basically replace the PUD reserves we drill each year with new PUDs. We’ve been 79% to 80% proved undeveloped relationship for the last 15 years.
In 2008, with the meltdown in the economy and in the industry with the commodity prices plunging, we brought our drilling operations almost to a standstill like 2008, early 2009, during that timeframe we became much more comfortable that the price of oil coming back quicker than the price of natural gas, mainly because of all the shales that have been just recently discovered, and all the drilling that we knew that would occur in those fields just to hold leasehold. So we’ve begun look into our prospect inventory to where we could increase our liquids production luckily by the areas that we’ve been developing for years and years. We had a lot of good acreage that had good oil potential, good rich natural gas drilling potential. So we didn’t have to go out and completely reinvent the wheel.
We made good progress towards increasing our liquids production, our three core areas today that we spend most of our E&P budget in, is in the Granite Wash in the Texas Panhandle and the Marmaton in Oklahoma Panhandle and then Wilcox play in Southeast Texas.
Our goal for the last 27 years now has been each and every year replace at least 150% of our annual production with new reserves. We’ve met that objective each and every year for the last 27 years. Last year we replaced a 176% of our production with new reserves. This year we will achieve somewhere in that 170% to 200% replacement ratio about the time year-end gets here. We’ve met our objective each and every year of those 27 years, which I don’t think another E&P company can say that.
Over those 27 years, we replaced on average of 218% of our annual production. We’ve not done that with acquisitions, we made acquisitions during the year, but we don’t want overly dependent on acquisitions in order to meet our annual objectives. Our basis for doing that is through the drill bit, through our prospect inventory and through our drilling operations.
On the production, as you see on the left hand part of the slide, between 2004 and 2008, we were on a nice trajectory for growing production. Production was growing on average of about 16% per year with a slow down in late 2008-2009. You see the drop-off of the production in 2009. We are fully aware that the production would be decreasing, but with the state of the economy and the industry at that time, we still feel like that was the right thing to do is slow down our drilling operation.
We began drilling fairly aggressive late in 2009, much more aggressive early in 2010. We were drilling at the rate high enough to have production increases year-over-year for 2010. But what happened is we ran into a complete road block and trying to get wells completed. There wasn’t enough of an infrastructure for us to get our wells fraced when we got them drilled.
It’s really the second half of 2010 before we were able to get many of our wells drilled in our core plays. But you can see on the right hand part of the slide, our quarterly production as you can tell as we began to get wells completed, production came up very nicely, production in the third quarter of ’10 was up 6% -- up 8% in the fourth quarter ’10. For the first nine months of this year, production is up 24%, over the first nine months of last year. Our guidance this year is we will produce somewhere between 32,000 to 33,000 barrels equivalent per day for the year, in 2011.
But good progress, I think we’re on the road where we were prior to the meltdown in 2008 and having some very large year-over-year production increases. As I mentioned, our focus become almost entirely, if not totally entirely, on increasing our liquids production in 2009. In 2010 our production, our liquids production increased 11%. This year we’re expecting our liquids production to increase about 30%. 2010 our liquids production was about 31% of our total production. This year it will be in that 37% of our total production, next year it should be again the 40% to 42% of our total production range. So, continuing to make good progress in growing liquids production.
What we’re doing most of that is in the areas, is in our three core areas. One of them the Granite Wash in the Texas Panhandle. That’s an area we’ve been in for the last 20 plus years, drilling different formations, drilling mostly vertical wells up until in – really into 2010. But the Granite Wash play emerged maybe the most economic play we were participated in the Texas Panhandle. Its about 11,000 foot deep, we drilled almost 4,000 foot laterals, 12 stage fracs, not a high-pressure frac like you see in some of the shale plays. The well is costing us about $5.5 million to drill. We book on average a little over 4 Bcf equivalent of reserves. The production is about 50% liquids, 50% residue natural gas.
Thus far this year, we drilled 14 wells, production averaged 30 days initial rate production, has been about 6.5 million equivalent Mcf per day for the first – for the 30 day average. We will drill somewhere around 19 wells, complete 19 wells this year in the Granite Wash. We will spend around $85 million. We’ve 75 to 100 prospects identified or drilling locations identified. Now we can drill – drilling 20 a year. We’ve a minimum of three to four years left drilling in the drilling [inventory].
What we were able to do this year is we were able to add enough acreage. We will replace the acreage that we drilled on this year, so we extended our prospect inventory life, another year. We think we will be able to do that. It’s not an area where you can add 20,000 30,000 40,000 acres in a year. But you can pick up 500,000 acres here and there, in some good areas, but it takes a lot of hard work to do that, but it’s been a great area. I think it will continue to be a great area for the next 5 to 10 years.
Our newest endeavor, we got into in the middle of 2010 with a shallow oil play in Oklahoma Panhandle. We currently have about 84,000 net acres in the play. We think by yeah-end, we’ll up to around 100,000 acres. The wells are about 6,200 foot vertical depths. We use 4,000 foot laterals, 16-stage slick water fracs. It’s a fractured carbonate play. We’ve wells in this – thus far this year, we’ve drilled 25 wells; some of the wells have come on in the range of 800 to 1000 barrels a day, some of the wells come on in the range of 50 to 60 barrels a day.
What makes the difference is where you’ve the natural fracking occurring when you’ve the bigger frac, fracturing occurring, you get to highest more prolific wells, don’t know that it’s really going to make any difference on total ultimate reserves, but of course the rate of returns are always better when you get your inventory turned over quicker. But 100,000 acres, we’re pretty – we’re comfortable at this stage. It will be drilled on at least 320s. So, we’ve 300 plus locations. I’m just using 320s across our acreage block. We’ll drill somewhere around 34 wells – 35 wells this year. So, again, 8 to 10 years of inventory life in this prospect.
Wells come online in the range of about – on an average, in the range of about 245 barrels a day, looking about 130,000 barrels equivalent. It’s 78% crude, 14% natural gas liquids, and then, about 8% natural gas. So, entailed with oil prices in the $100 range with $2.5 million oil costs, the rate of returns in this field are now very prolific.
Another play that we’ve been involved in for – well since 2003, we drilled a discovery well in this field, it’s a vertical field, there is no horizontal drilling going on. I guess, today it would be considered non-conventional, but it’s been very productive for us over the years. We drilled 92 wells, we’ve had 75% success ratio. It’s a seismic play. We now have about 48,000 acres across the play. We’ve 3D over about 320 square miles now. We drilled 13 wells to-date this year. The wells – the average reserves in these wells are about 260,000 barrels equivalent for oil. It’s about 50% liquids, mostly natural gas liquids. We drilled around 15 to 16 wells this year. It cost about $50 million to do that.
We’re able to add our acreage block very nicely in this area with all the emphasis on horizontal drilling in shales and tight sands, we’ve seen very little – we’ve [hardly] any competition in this field for acreage. So, we’ve been able to maintain a very low acreage cost in the major mineral owners, which are basically two in this area working with this very, very well to continuing to add to our inventory in this field.
We did complete an acquisition in the third quarter. It’s in Arkoma Basin, which is in southeastern Oklahoma. It’s a dry gas area. We purchased 31 Bcf equivalent, so it was 83% proved developed. We paid $30 million for or less than a dollar in Mcf. It’s a Woodford and Hartshorne Coal play, 2.5 to 3 year oil and gas, you won’t drill, but it’s entail we paid less than a dollar in Mcf.
We also got 55,000 HBP, held our production acreage in it. We allocated none of the purchase price to the acreage. Gas prices get back north to $4. There will be a lot of development drilling across this acreage block. But if it doesn’t happen, the economics are still very well on the acquisition that we’ve made. We’re not planning on doing any drilling in this field for probably in the next couple of years.
This year, our budgets for E&P segment was about $435 million, $357 million of that will go into actually drilling cost on drilling wells, 52% of that will be in our three core plays, that’s the Granite Wash, the Marmaton and the Wilcox Play.
Moving to our contract drilling segments, we started the year with 121 drilling rigs. Thus far this year, we’ve added five new rigs. All five of those went into the Bakken. We’ve two more that will be coming out in December. Those are going into Pinedale. They’re all under two to three year contracts whether that add sufficient enough margins to have the rigs paid back, cash-on-cash payout within the three-year period, which is our criteria for adding rigs. We want a three-year payout. So if the rig goes down at the end of three-years, we recouped all of our investment and still own an asset that’s very, very valuable at the end of those – at the end of the contract period.
We’ve a contract to build one new rig thus far for next year. I think we’ll continue to see opportunities to add rigs, but we don’t build rigs on a spec basis, we only build them when we’ve contracts.
Utilization has been increasing very nicely. We were running an average of 79 rigs for the third quarter. We’re running 83 rigs today. I think it will continually to gradually increase, mostly in the 750 to 1,000 horsepower range, which entails really the only area that’s – that has demand today that we’ve the ability to increase within our drilling fleet without adding new rigs. The 1,200 to 2,000 horsepower rigs are fully utilized. The red shading, it’s the utilization of each of those size of rigs, which entails the 1,200 to 2,000 horsepower rigs are fully utilized.
Where we’re seeing the increase in utilization currently in for the last two or three months has been in the 750 to 1,000 horsepower range. Those are the rigs that are drilling the shallower, primarily all horizontal wells. A lot of them are going to work in the Mississippian play, which are – we’re based in Oklahoma, and the Mississippian play is rather in our backdoor. That play is very exciting to us, overall corporate wise. It needs hundreds of millions of dollars spend in the midstream operations in that area, which we already have three projects going right now in our midstream operations.
We have about 40,000 net acres now in our E&P area to drill for and they were putting the rigs to work without [having] to move them across the country. So, that feels a pretty important field to us from all three segment aspects. Not a whole lot of activity on the real shallow rigs, those rigs are really the ones that will drill a shallower vertical gas wells really takes gas somewhere in the $4.5 to $5 range, I think before you see a lot of activity in that size of fleet. Ultra deep rigs in excess of 2,500 horsepower, the slide hasn’t been updated for this week.
We did put one of those rigs to work, 4,000 horsepower rig. It went on the payroll of (indiscernible). It’s under contract that should last 400 to 500 days on one well and that’s kind of that how those big rigs historically have worked. They don’t work consistently. When they do work, they make a lot of money just because there is not very many of them out there in the industry. When someone needs this 4,000 horsepower rig, it is the only one in the United States. So, they really have no competition for it.
But the last well, it was on, which was – which ended about two years ago, it was on the same well for two years. Hopefully this – it will be on this well for a year and a half to two years. So when it works, we make a ton of money and then when it didn’t work, it maybe a year, two years in between contracts, but that’s pretty typical for that size of rig. So we’re excited about finally getting it back to work.
Day rates have been improving, as it entail very nicely quarter-to-quarter, between fourth quarter of 2010 and the third quarter of 2011. Day rates were up nearly $3000 a day, or about 17%. They were up in the third quarter this year, $450 a day over the second quarter. We’re expecting them to be up on average of $100 to $200 a day in the fourth quarter over third quarter. And of course we’ve additional two rigs coming out in the fourth quarter of this year that are going into Pinedale.
What [helps] me sleep better at night is about 80% rigs of our rigs are working either in rich gas plays or in oil plays. I think we’ll continue to see weakness in the dry gas areas. So, I think we will continue to see rigs coming out of those areas moving into either rich gas or oil plays. Thus far, there has been enough demand for those rigs coming out of those plays to go to work in other plays, keep waiting – for the little bit of weakness to come through. But so far there has been plenty of demand, which we’re very, very pleased about.
But I think you’ll continue to see rigs come out of the – some of the more dry gas, of course we’ve seen it in the Barnett, we’ve seen it in the Haynesville, and I think you’ll continue to see it in those two plays. Thus far not much of it showed up in the Marcellus, which we’ve no rigs up there, but we do have a midstream operation in the Marcellus.
Speaking of the midstream, as I mentioned we really got into this business in 2004 when we were 40% partner in the company. We bought 100% of it in 2004. It’s certainly in the timeframe that we’ve had superior midstream company. I’m not seeing the kind of activity that we’ve seen – that we’re currently seeing in that segment. The guys that run that segment have not ever seen in their lifetime the kind of activity that we’re seeing right now in the midstream segment.
We started off this year with a budget of $43 million. We doubled that budget in mid-year of this year. I think very, very easily, the next year the budget could be twice. The budget we currently have which would put it up in the $150 million to $160 million range, it could be as high as $200 million to $250 million this year. There is not the infrastructure out there to process all the gas, the rich gas is coming on, which you would take in Northern Oklahoma where there’s been oil and gas drilling for years and years and years, but you wouldn’t have infrastructure problems, but there is no ability to process natural gas in Northern Oklahoma.
As I mentioned, we have three projects going on right now. They’ll start off smaller, they’ll start off and at the of 20 million a day kind of range, but with the kind of drilling activity the operator is currently playing in those areas within 12 months to 18 months, you could be looking at $75 to $100 million a day kind of processing requirements of some of those projects. We’ve added – late last year – about this time last year we brought online our additional facility in Granite Wash we were at $110 million a day, we were already in excess of that capacity. We’re adding another $40 million a day to our Granite Wash facility, and that this continues to expand.
I’ll turn it over to David Merrill, who will run through the financials.
Larry just covered some exciting things that are going on from an operating perspective in all three of our segments. You’ve seen we had a good track record of consistent growth, and now I want to give you an idea of how we keep our financial health in order.
Our capital structure as of the end of the third quarter, you can see it shows that we maintain a strong capitalization with low financial leverage. At the end of the third quarter we had $250 million of bonds. We had $55 million outstanding on our bank facility, so $305 million of long-term debt, about $2 billion of shareholder’s equity and total assets a little over $3 billion.
Diving into the debt structure a little bit, it consists of bonds in our bank facility. The bonds that we had outstanding as Larry mentioned early on, we were a first time issuer in the public debt market during the second quarter of this year. We did $250 million, 10 year senior subordinated note issue, had a 6.158% coupon. We have added some diversity to our capital structure, which I think was very nice, prior to that we had just had bank facility debt in place.
One of the advantages of the structure that we chose, our bank facility is an unsecured facility, so that’s why we issued subordinated notes. It creates – it gives us a little additional leverage on our borrowing base in that regard.
Talking a little bit about our bank facility, again it’s unsecured. The 5-year facility, it matures in September of 2016. So you can see through the notes that are out there, in our bank facility we have nothing coming due within a 4-year time span write down. We currently had $55 million outstanding on our bank facility.
We have an elective commitment amount of $250 million and a borrowing base as determined by our banker this fall of $600 million. And one particular note on our borrowing base is; it only consists of our oil and gas properties and cash flow from the midstream business. The fleet of 126 rigs isn’t even in our borrowing base. So, obviously there’s a lot of additional capacity if we had a need for capital of that magnitude.
Highlighting a few of the credit statistics, where we have a very conservative statistics. As at the end of the third quarter, our debt to the last 12 months EBITDA is 0.6 times. Our interest coverage for the last 12 months is 47 times. Our debt to proved reserves and debt to proved developed reserves as of the end of last year, given that’s the last time we reported our reserves was $1.57 and $1.97 per BOE respectively. Our debt to capitalization percentage at the end of the third quarter is 14%. In being a new public debt issuer, we received ratings from all three rating agencies. They gave us the corporate family rating and the rating on our subordinated notes. S&P and Fitch rated our notes at a BB minus each, and Moody’s is a B3.
I don’t plan on covering or going through all of these credit metrics here, but instead of just talking about our current metrics, I wanted you to see that we have a track record of conservative financial practices. All the metrics that you see here are very conservative, but at the same time, we’ve had a lot of consistent growth in all three of our segments. So we do keep our financial house in order. We have a track record of good sound fiscal policies.
Revenues for the first 9 months of 2011 were $863 million, a 37% increase over the same period in 2010. 44% of our revenues came from contract from E&P segment, 39% contract drilling and 17% midstream. EBITDA for the first 9 months of 2011 was $436 million, 62% of our EBITDA came from the contract drilling or the E&P business, 33% contract drilling and 5% midstream.
We do have hedges in place. Our objective each year – each production year that we go into, we like to be 50% to 70% hedged for crude and natural gas. For 2011, we were there on both regards. For 2012, we’re already there on the crude side. We’re not that hedged yet on the natural gas side. We’re not interested in locking in the process that we see right now, but we’ll continue to look for opportunities and lighter things on as there are opportunities.
Our capital expenditures for 2011 budget, excluding acquisitions was $695 million. We've done about $60 million worth of acquisitions during 2011. By segment $435 million is budgeted for E&P, $174 million for contract drilling and $86 million on the midstream. And we are in the process of finishing up our 2012 capital budget. We’re not ahead in position to communicate it just yet. We’ll meet with our Board next week and so stay tuned for more information down the road.
And with that, we’d like to open it up for any questions anybody has.
Yeah, I’ll start with one on your 2012 budget, which I know you can’t tell us yet, but are you guys – I think in the past you generally spent pretty close to cash flow or kind of targeted cash flows, is that still the plan for next year or given the opportunities that you have ahead of you or are you thinking of it differently?
This year we are – we’ll be about $150 million in excess of cash flow. We’ve done about $60 million worth of acquisitions, which is part of that and had some very good prospects to be drilling in. So, that was one of the primary reasons we’ve outspent our cash flow this year. Next year we’ll – depending on how things materialize as we had set up on the midstream side of the business. We’ll probably be in excess of our cash flows, nothing drastic, it could be in $100 million range, but again we’ll evaluate those opportunities on the midstream business as they do materialize and Larry had indicated that, that could range anywhere from $150 million to little over $200 million or so.
On the midstream?
On the midstream side. On the contract drilling side, we don’t have as many new builds contracted right now as we did in 2011. So Larry had mentioned that we had the one – we have the one new drill planned for ’12. So, our capital expenditures will be down from 2011 and ’12 assuming we don’t have additional new build to be on the one that we’ve talked about. And our spending on the E&P side ought to be somewhere in the line of what we spent for 2011 excluding acquisitions.
And I’m going to speak one more in here before we quit – before we close, but – what do you see on the Marmaton from a competitive standpoint? And I know you guys said – I think you said you’ve a pretty deep inventory there, but have you drilled enough wells there that you would feel comfortable accelerating that, it seems like its pretty good return type of area?
To a large extent it depends how long or what we’re seeing opportunities in other areas. We don’t want to put all of our [rigs] in one basket, in one field and forget about what we’re going to be doing for the next three or four years. Certainly we could put four rigs to work at Marmaton, but we need to continue to develop different areas that we’re going to be drilling in over the next 5 to 10 years in new areas.
So the two rig program, it’s a very labor intensive, I mean, we drill the wells now in 13 days, it takes about 25 days to get wells drilled and get them completed and get them online. Now that’s not, there’s 25 days calendar days in a row. You’ll have stages in between waiting on frac crews and things like you had to get there. So it’s a quick drilling operation, its very labor intensive and of course today labor is a major shortage throughout the industry. So, not really expecting – we had expected to move to three rig drilling program early next year, but we’re drilling the wells fast now that we’ll get the acreage proved up, and there’s really no – there’s no reason right now for us to expand our level of activity there.
Okay. Well, guys thanks for coming down, and thanks for presenting.
Thank you everybody for coming. I appreciate it.