This is the third in our series of CEO Interviews in the energy industry (please see our previous interviews here and here). Today’s interview is with Thomas L. Ward, the CEO of SandRidge Energy (SD). Related companies are the royalty trusts SandRidge Permian Trust (PER), the SandRidge Mississippian Trust I (SDT) and SandRidge Mississippian Trust II (SDR). Joining Seeking Alpha Editor Leland Montgomery are Contributor Mike Filloon and Contributor Devon Shire. Mike’s accompanying article appears here, and Devon Shire’s article appears here.
After leaving Chesapeake Energy (CHK), which he co-founded with CEO Aubrey McClendon, Tom Ward set out in 2006 to build a new exploration and production company based on his 23 years of experience acquiring promising acreage. Please also see SandRidge Energy’s latest Quarterly Earnings Call Transcripts and detailed company presentations.
The following is our interview.
Seeking Alpha (SA) – Given the extent of asset buying and selling SandRidge has done over the last few years, could you give us an overview on what you’ve done and why you’ve done it to set the stage for our discussion today?
SandRidge CEO Thomas Ward (TW) – SandRidge is a fairly young company that was formed in 2006 with the purchase of a gas field in West Texas. When I left Chesapeake in February 2006, we bought the Piñon Field in West Texas based around the thought that natural gas prices would stay at what I thought then were reasonable prices, above $7 basically.
Up until then, my career had been a Chief Operating Officer of Chesapeake for 23 years, and I had always focused on buying assets, and then trying to understand why that asset wasn’t developed by our predecessors, who are much smarter than most of us. And so this natural gas asset in West Texas was very unique in that it is the only field in the United States that produced about as much CO2 as it did methane. And that kept the production of that field down over the course of time until you had gas prices at high levels in relation to what they have been historically.
So the original premise about building SandRidge was around the natural gas story in 2006. And by 2008, our management team believed that the story had changed and that we were headed for a period of low prices for natural gas; and we decided we had to make a change. So in late 2008, we hedged all of our natural gas production for two years, while we made a conversion to oil. In March of 2009, I went to our Board and recommended buying assets in the Permian Basin. And that was at a time when oil was $39.96 and gas was $4.13 an Mcf, and we’d hedged our gas at just over $8 an Mcf in late 2008.
So then we moved forward with an acquisition program in the Permian at a time when others weren’t buying oil. They were still looking for natural gas, assuming that there would be a bounce back in natural gas prices, and were still chasing the tight-gas formations in the U.S. And we’d chosen not to drill in tight gas reservoirs and stayed looking at carbonates for the most part; and so then looked for the best places to find oil that other people weren’t trying to buy, and that was in the Permian Basin.
We’ve made two acquisitions, one in 2009 and then one in 2010. And those acquisitions were for about $2 billion, the first being an asset from Forest for $800 million, and then buying Arena Resources for $1.2 billion in 2010. And then we started selling off some of those assets and keeping the shallowest portion of the Permian, which is the Central Basin Platform, and using that capital to fund the acquisition of leases in the Mississippian play, which is also a very shallow carbonate oil play in the Mid-Continent and that’s the area that we use for growth today.
SA Contributor Michael Filloon – With your purchase of 2 million acres in the Mississippian at about $200 per acre, maybe one of the biggest steals in recent memory, give the value of the acreage and why you would choose to monetize these assets as opposed to develop and create cash flow through the drill bit?
TW – We’ll do both. So we bought more acreage than we could drill in a reasonable time frame. Some companies will keep 30, 40 or 50 years of drilling inventory and we’ve chosen to try to narrow our inventory down to around 15 years of time when we bought in the play. By being the first company to understand the scope of the play, we were able to go buy very inexpensively and so we bought with the idea that we would have other companies come and help fund our drilling in the play.
So we used the joint ventures as a source of financing – one source of financing, and then royalty trusts as another source of financing. And we sold 550,000 acres and raised $2.33 billion on an investment of just $400 million and still kept three quarters of our investment in the acreage. So, we still have over a 15-year inventory of prospects.
SA - The Mississippian is an interesting asset as it is cheap to drill and is repeatable. If I were to compare the Bakken to the Mississippian, I would estimate a Bakken well costing between $9.5 million and $11 million with an average Estimated Ultimate Recovery (EUR) of approximately 600,000 barrels of oil equivalent. And actually, I’m just using a general number that Continental Resources (CLR) throws out there, because they are all over the play.Your estimated well cost in the Mississippian is about $3.2 million, and it looks like the majority of your more recent completion models would give you an EUR close to 500,000 barrels of oil equivalent. Although, this is a very generic comparison, why do you believe the Mississippian does not get more positive attention?
TW - Well, half of the production is gas, so I think there are people who believe that’s a negative where I look at as upside, because the rate of return in our opinion is superior to the Bakken. I like the Bakken play, but it costs more to development and was already a crowded market by the time I wanted to buy oil. So the Mississippian was a better place to have a low entry cost and we see about 80% of the revenue that we have coming from oil, but having upside for natural gas if gas prices rebound even to $4 an Mcf, which I believe is more realistic to the market in the next year or so than the $2 that we’re at today.
The other reason is there is a high level of water production that comes along with the Mississippian. It is a very large stratigraphic trap, but as I mentioned about the Piñon field, you have to understand why this field wasn’t discovered and drilled over time, even though there have been thousands of Mississippian wells drilled over the last 50 years. But in a large portion of this area, it produces a large amount of water. So where others saw water, we saw oil and by skimming off a 10% oil cut, we can produce the quantities of oil that you mentioned and still have in our opinion the best rates of return in the U.S. today.
SA – Also, as we discussed, the Mississippian well costs are quite low, which is understandable, given it is a very shallow play, how does the produced water disposal infrastructure affect this decreased well cost?
TW – What’s critical, you have to put in the disposal system in order to deal with the water production. So, in another words, if you were trying to trap all this water, we assume each well produces about 3,000 barrels of water a day to produce the 300 barrels of oil equivalent per day of oil and gas. So, we produce a large amount of water and having an infrastructure in place to deal with that water is critical. And you have to have a very large land position in order to put that infrastructure in. So, it’s also a barrier to entry for other companies.
SA – I’d like to return to something that you mentioned previously. During the flurry of interest in unconventional formations, you chose to go after conventional acreage in the Permian Basin. This was obviously a great move, but what reasons did you have for going after conventional oil when the market was so excited about unconventional gas?
TW – It’s very simple: I don’t care for ultra-tight rock [Editor’s note: meaning, very tight shale requiring hydraulic fracturing, or “fracking”]. That’s not to say that there aren’t great places to drill in shale. But shale formations are a nanodarcy [a measure of permeability] reservoir and if you look at the theory of permeability, that’s about a thousand times more tight than millidarcy, which is a thousand times more tight than a darcy. And so over the course of time of our industry, we went from producing darcy reservoirs in the very earliest days of oil and gas exploration to millidarcy reservoirs and from 1948, when we created fracture treatments, to the recently nanodarcy reservoirs which are one thousand times more tight than a millidarcy.
The reason to go back through all that is that anytime you are producing from just strictly a shale, and I don’t consider the Bakken a shale, I consider it more of a dolomite, but let’s just say it is a straight shale reservoir, the odds of having a poor well are much greater than having a good well, especially if you buy all the acreage first, then have to drill wells. It’s just a riskier proposition. So, in the Haynesville Formation for example, there is a small area that geologically has storage capacity to be able to produce at a very tight rock. In the rest of the area, it is high cost in order to get that gas out, and takes very high natural gas prices in order to be profitable, and I just thought it was too risky. And I didn’t know enough about the reservoirs to be able to predict where they might be good and bad.
SA – Great.Would you be interested in purchasing acreage in any of the U.S. unconventional plays, or are you currently going to focus on the Permian and Mississippian in the short-term?
TW – No. We purchased the cheapest oil in the country right now. It’s being sold in the shallow waters of the Gulf of Mexico, so that was why we made the $1.275 billion acquisition of Dynamic Offshore Resources, LLC that closed this week.
SA – When do you believe the price of West Texas Intermediate (WTI) crude oil will strengthen to Brent crude? And do you believe there are any short-term catalysts that would cause this to happen?
TW – I believe that will happen as we actually build substantial additional pipeline capacity to and from the hub at Cushing, Oklahoma. So, I think that takes care of itself, it probably doesn’t start until 2013, but if you look at the futures market, they are already looking forward and saying that there should only be about $5 premium out at the end of this year versus the $20 premium that we’ve had recently. And I don’t have any reason to believe the futures aren’t correct. And if history repeats itself, we’ll probably overbuild that capacity and have over time the capacity to deliver more oil to Cushing than we have to deliver.
Contributor Devon Shire (DS) - Back in 2008, how did you know you needed to make such a huge transition to an oil-focused company?
TW – It was not a pretty time.We knew we had to make a move and we didn’t have the reserves to live on that other companies did, because we were a brand-new company.So, we knew if we made a bad choice, which we did in buying natural gas in 2006 and knew we had to move to oil, that decision was actually quite hard. Remember, back in September 2008, the world was falling apart.
Since I came out of the University of Oklahoma in 1981, and from 1983 until 2008, we were basically chasing people out of the U.S. drilling business. All of a sudden in 2008, you had this influx of capital from the largest companies in the world that can drill wells at a price that even large independents in the U.S. can’t afford to drill. That was the major catalyst – the influx of capital that was coming back into the market that I’ve never seen before.
SA – Can you see a point in the future when there may be natural gas assets for sale on the cheap? Is there a price that you’d be willing to buy natural gas assets at?
TW – No, again for the same reasons, other companies are willing to drill for natural gas at a price that I can’t see as being attractive – at least that can’t compete with our oil assets. So I don’t see the two commodities getting back at least for the next several years to a point that you’re back to that six to one BTU equivalent, that is gas to oil. And as you know, today we’re at 50 to 1. And I just don’t see that happening, because it’s much easier to find natural gas in the U.S. than it is oil, and I think these companies would drill for it at the time when we wouldn’t – when we’d still be drilling our Mississippian. So our growth target is just the Mississippian. We’ve bought the Gulf of Mexico that is extremely cheap, but the Mississippian is where the main drilling will be for us in the U.S. So I do not see us buying natural gas assets.
MF – Some investors misunderstood the acquisition of Gulf of Mexico assets as a diversion for the company. Can just briefly describe the strategy there?
TW – The important thing to understand is that we have a three-year strategy that no other company in the U.S. has; and that’s that we’re going to triple EBITDA, we’re going to double our oil production, and we are going to increase production. And by the end of 2014, we’ll be doing it all within our cash flow. And all the while, we’ll be improving our credit metrics.
So in order to meet those four goals, we had to raise some capital, and we needed to spend in about $1.8 billion in 2011 drilling wells to get the first year of that three-year plan in place. And we were able to do that even though we only had about $410 million of cash flow from operations. By selling the two joint ventures – creating the royalty trust we did, plus the selling of some of the assets that weren’t on the Central Basin Platform in the Permian. And that left us in 2012 in a much better position. So we only needed two transactions in 2012 in order to fully fund 2012.
One of those was a financial transaction, which was buying Dynamic Resources, and that acquisition gave us a better credit position, increased our production by 25,000 barrels a day and gave us the ability then to move forward and improve our credit metrics. And that left us only with this last transaction, which is the royalty trust that we’ll be pricing this week [priced April 17], and then with that we’re fully funded for our cash needs in 2012. So acquiring Dynamic Resources was because that was the only place we could go buy oil at a price that allowed us to be accretive on oil metrics. And that’s just because people don’t want to be producing in the Gulf of Mexico in 300-foot-deep water, and we just don’t see that as a reason that makes it worth one-third as much as Permian oil.
SA – We received several reader questions around the royalty trust. Have you been surprised how well the SandRidge-sponsored royalty trusts have been received by investors, and will you continue to use them as a capital raising vehicle? And how do the IPOs of the trusts improve your cost of capital?
TW - For a few reasons, we are not surprised at the positive reaction that the royalty trusts have received in the market. In an environment with a 2% 10-year Treasury bond and very few places to get a yield, people are searching for alternatives, and the new drilling trusts are one way to achieve this. An investor can get (1) a high single-digit IRR over the life of the trust, (2) a very high current yield that is increasing for the first several years of the trust, (3) downside protection via commodity hedges in the first few years and the protection for the subordinated units that the sponsor holds, (4) longer term commodity price exposure, (5) the ability to make an investment directly into a given play or basin (such as the Mississippian for SDT or SDR and the Permian Basin for PER), (6) a tax-advantaged structure, and, (7) the ability for appreciation in the unit price. All of these factors seemed to resonate with investors. For our two royalty trusts, if you bought SDT on the IPO date you would have a 55% total return and if you bought PER your return would be 30%.
For SD, the trusts are a great cost of capital. There is a large trading multiple arbitrage between where SD trades, where these trusts price at the IPO and where they ultimately trade in the market. By packaging certain of our assets into these trusts we are able to monetize this difference in the multiples – it’s no different from a midstream or E&P company creating an MLP and dropping down assets. So we like the trust as a source of capital and may look to use them in the future.
DS – You’ve got some pretty good natural gas assets. Would you sell them to someone who's interested, or is there just no market for them?
TW – We’re really down to one natural gas asset in the Piñon Field, and we don’t see ourselves drilling there in the future, so we've said that at the right price we would sell.
MF – About the Mississippian, which you’ve described as about half gas, I know that that particular play gets oilier as you go to the southeast or to the east. Could you tell me how much better that play gets as you get down thorough the Mississippian and get into like Sumner County, Cowley County, Osage County, that area?
TW – Our latest presentation on our website (slides 7-14) shows the wells that we’ve drilled in each county and what they’ve produced in each county. And what we’re seeing is about the same oil to gas ratio on the horizontal wells all the way from Comanche County to Noble County. So even though the vertical wells produce more oil by county, once you start drilling a lot of wells throughout the counties, we’re seeing about the same oil-to-gas ratio as we move to the west. So far the best county we’ve drilled in is Harper County, Kansas. But that’s also a county that we've only drilled nine wells that are producing. And in Alfalfa County for example, Oklahoma, we produced 119 wells. So I don’t think there is anything different between Harper and Alfalfa. I think just statistically you have a larger set of data in some of the counties over others. Today, there are 534 wells that have been drilled in the Mississippian, and 64 active rigs. So, there is a lot of data that’s coming in on the Mississippian and I get very little push back about the Mississippian being a good play anymore.
MF – What I find surprising about that play is that, it’s basically, you and Chesapeake are out there as big players, Range Resources and maybe Shell (RDS-A) they’ve got a couple of rigs out there. What surprised me most is that we don’t see more big purchases in the area, due to how much better the play has gotten or at least how good it looks today.
TW – The original play is fairly well bought. So, I think you will see other companies buy other companies, but the acreage is basically gone. And so now the extension play that we developed is fairly new, and we’re just drilling our first wells there, in fact they’re starting this month. And I think it’s just as good as the original, but it’s yet to be proven.
MF – How do you keep the lid on something like that, when you’re creating that much value for shareholders? I mean, if you were a hedge fund manager who invested $400 million and turn it into $8 billion over the last three years, you would be, tell us to the town.
TW – Well, we had an idea that others didn’t see and so that’s why we were as aggressive as we were. The market didn’t like us buying all this acreage if you remember it last August. When we announced we were buying another half million or 1 million acres of land then the market didn’t carry forward for the purchase. And since that time we brought in two new partners, and still have room if we’d care to we could bring another partner, right now. So, we had an idea around a play that other people weren’t looking at as they choose to drill in tighter reservoirs around the U.S. and I felt very comfortable with it. So we were willing to make the investment before others were.That, and being comfortable in a reservoir that I had worked most of my carrier.
MF – So most of that value hasn’t been reflected in the stock price since you’ve done it. Do you think it will take just time as production ramps up and the company effectively deleverages?
TW – Sure, they just need to see steady quarter-over-quarter growth. I think that you would have seen the same thing how the Bakken drillers when they first started and now after they produced quarter-over-quarter growth. I don’t know when our stock will move, but you can’t triple EBITDA in three years and not have your stock price double or triple along with it.
MF – That’s what I see in a lot of companies that are focused on unconventional resource plays that it looks to me like they’re all trading at pretty reasonable EBITDA multiples now, yet they’ve got 15 years of growth ahead of them. How would you go about valuing a company like yours if you were me?
TW – Well, If you start it out with why I think we’ll see more value than others is that the other plays just cost a lot more to drill, and the rates of return are less. So, we should grow at a higher level by spending less than other companies, and it should be pretty evident as the quarters go by.
SA - I just don’t understand why there’s not more of a premium in your stock or someone else’s who has an inventory of drilling locations that’s going to last another decade, it’s like a technology company that’s growing at 20% a year trading at a single-digit P/E multiple.
TW – Yeah, the reason is because about half of the people that invest look backwards. So, on a trailing EBITDA multiple, we trade at a premium and on a forward-looking EBITDA multiple, we trade at a discount.
SA – Tom, where do you see oil prices headed in the current environment and going forward a year or two?
TW – The great thing is that I don’t have to be a great prognosticator on oil prices, as long as they’re over $100 a barrel, because at that price we make 100% rates of return. And so you see us having the most hedged oil book of any company in the U.S. I still believe that you’ll have ups and downs in the oil market, we’ll see volatility like we have every year, and you’ll be able to have prices range between $90 to $120 a barrel and what we have to do as a company is just be diligent in locking in anything that gives us 100% rates of return. So any time you see oil at a $100, you’ll see us hedging out our oil fairly aggressively. In fact, we have over 80% of our oil hedged for 2012 already.
SA – Tom, how important is it that the Keystone XL pipeline goes through?
TW – Well, we hedge on WTI pricing, so it’s not so important to our company today, but if you look out in the future, it becomes important that either the Keystone or the Oneok Partners, L.P. (OLK) line that they will be coming through from the Bakken on down. I see it as very important or else you’re always going to have WTI pricing remain at $20 under Brent.
SA – Is there an opportunity for some smart operator, someone who is opportunistic, to come in and buy natural gas assets at these unusually low prices and valuations?
TW – Sure, there is and I fully believe that gas prices will double from here in the next year. The problem is that even when you double from here, you have a very difficult time in today’s market pricing to make a rate of return that’s acceptable to a public company. And so that’s where I find it challenging, but yes if you want to just go make an acquisition today and produce that gas, I think it’s a good time to be buying gas.
DS – We drilled ourselves into lower natural gas prices, are you concerned about doing that on the unconventional oil side?
TW – No, just because oil is a world market, and the world has a high demand for oil and even though I think we can become self-sufficient overtime, I don’t see the U.S. coming to a point that we flood the world with oil. The reason that we have an oversupply issue with natural gas is that we just can’t transport it around the world like we can with oil.
MF – Looking at the stock price of your company, it looks cheap to me given its growth prospects, increasing cash flow, etc. Would SandRidge be for sale at the right price?
TW – Well, actually by being a public company, we’re for sale everyday. But my real answer is that if we really believe we’re going to triple our stock price in three years, it would be a difficult time to sell it.
SA – Thank you, Tom.
Tom L. Ward has served as Chairman and Chief Executive Officer of SandRidge Energy, Inc. since June 2006. Prior to this, he served as President, Chief Operating Officer, and a Director of Chesapeake Energy Corporation from the time he co-founded the company with Aubrey K. McClendon in 1989 until February of 2006.
Mr. Ward graduated from the University of Oklahoma in 1981 with a Bachelor of Business Administration in Petroleum Land Management. He is also a member of the Economic Advisory Council of the Federal Reserve Bank of Kansas City.