Resource-rich Magnum Hunter is drilling, building asset base

Two roughnecks trip pipe in Eagle Ford

AN INTERVIEW WITH GARY EVANS, CHAIRMAN AND CEO OF MAGNUM HUNTER RESOURCES

OIL & GAS FINANCIAL JOURNAL: Gary, in the 1990s you built an oil and natural gas company called Magnum Hunter. You subsequently sold it to Cimarex Energy in 2005 for $2.2 billion. Four years later, here you are building another Magnum Hunter Resources. What prompted your return to the oil patch?

GARY EVANS: When we sold Magnum Hunter back in 2005, I was bound by a two-year non-compete agreement that prevented me from doing anything in the oil patch here in the US until June of 2007. During that time, I got involved in green energy, and I also went to China and became involved in taking a number of Chinese companies public here in the United States on US exchanges through a broker dealer I started with a partner called Global Hunter Securities. So that was my primary focus for a few years. What really led me in getting back into the oil patch was the financial debacle we all experienced in 2008. I was looking for a vehicle to get back into the business, and I found a little company in Houston that I felt could be used as that vehicle, so I took it over in May of 2009 and that's what led to the new Magnum Hunter Resources Corporation.

OGFJ: Are you still involved in green energy?

GE: Yes and no. I'm still involved with GreenHunter Energy, but we completely changed the business model from an earlier portfolio of renewables. At the time I started that company, the focus was on wind, solar, biomass, biodiesel, and ethanol. We've gotten completely out of those business segments and sold them off one by one. Starting in late 2011, we became involved in the water side of the oil and gas business. The company was completely reconfigured with a new business model and management team, and is growing quite rapidly. In many respects, it's a sister company of Magnum Hunter. We handle most of Magnum Hunter's water needs in the shale plays where Magnum Hunter is active, but that represents less than 10% of GreenHunter's current business. Water is such a large issue in these unconventional resource plays, and there are lots of different components to the business. We see a real need in the industry today and there is an opportunity for consolidation because most of the water business has been historically controlled by the "moms and pops" over the years and it is now a much larger, more sophisticated piece of the oil business today, and a necessary ingredient for shale exploitation success.

OGFJ: Is it still called GreenHunter Energy?

GE: Yes, we have a subsidiary called GreenHunter Water, but the parent company is GreenHunter Energy and it is publicly-traded on the New York Stock Exchange with a market capitalization of just under $100 million.

OGFJ: Where do you operate the water business, in the West or also in Appalachia?</p>

GE: Appalachia is our biggest operating region, but we operate in five states. We're in West Virginia, Ohio, and Kentucky. We're in South Texas in the Eagle Ford and the Mississippi Lime play in Oklahoma. We're in the process of expanding to the Bakken.

OGFJ: Early in your career, weren't you active in the energy banking industry?

GE: From 1977 to 1985, for about nine years, I was a banker in Dallas. I worked for two banks. One was National Bank of Commerce, which became BankTexas. It was a regional bank, and I went through the credit training program there and became a lending officer. Then I started up the energy division for the southwestern region for Mercantile Bank of Canada, out of Toronto, which I ran. We were an energy lender back when the big Texas banks were having all kinds of loan problems and capital issues. We were the new kids on the block with a clean portfolio, so we had a lot of opportunities to do some fairly innovative financings. We were a US corporation, so we could take net profits interests, overrides, and other equity kickers at a time when there was virtually no lending. It was a really profitable division for our entire bank, both in the United States and Canada.

OGFJ: No doubt this background in banking and finance proved helpful when you went into the oil and gas business.

GE: Financing is such an integral part of growing any business, but especially the oil and gas industry when all we're doing is burning through capital, whether we're drilling wells or making acquisitions. I think having a finance background gave me a bit of an edge. My first entry into the business back in '85 was a leveraged buyout of a well service company. So I got my hands dirty for about four years in the field running a well servicing company during a really difficult period in the industry, so that gave me some insight into the interworkings of field operations that some CEOs may not have today, especially guys with a finance background.

"We're very happy with the assest base we're built, but the stock market has been challenging. We're always felt that time would take care of that if we continue to perform. And that's what we're doing." — Gray Evans

OGFJ: You're on the board of the Maguire Energy Institute at Southern Methodist University in Dallas. Are you an SMU alum?

GE: I attended school at night here in Dallas at SMU while I was working at the two banks. My first year of college was at California State-Fullerton. I've been very involved with SMU for years and did some periodic teaching over there for the MBA program. The Maguire Energy Institute is a group of successful oil and gas executives, and we meet about once a quarter. We do a lot to promote the industry, including energy clubs at SMU, and we often recruit SMU graduates. SMU has some great programs designed for the energy industry. We help put together some of the classes for the finance curriculum, and a lot of the executives in the group teach there as well.

OGFJ: Let me ask you about your operations. Magnum Hunter has acquired large amounts of lease acreage in at least five resource plays. Was your company an early entrant into these plays, a fast follower, or a latecomer?

GE: That depends on the play. We were an early entrant into the Eagle Ford and the Marcellus – at least in the areas of those plays where we are operating. The same exits for the Williston Basin. We're the only US company involved in the Three Forks/Sanish/Bakken plays just north of the border in Saskatchewan. I would say the plays had already hit the radar screens, but the areas where we're involved had definitely not. That's why our acreage cost is typically quite a bit lower than what our competition have historically paid.

OGFJ: Is there a "sweet spot" in the Canadian Bakken?

GE: Well, Divide County is the county we're most active in North Dakota, and it goes right up to the Saskatchewan border on the Canadian side. Believe it or not, the shale doesn't know there's a border there. We're active in a field called the Tableland Field, and we've been able to make the play very profitable for our company. We really like that area, and it has some unique attributes in that there is royalty relief from the provincial government of Saskatchewan. We only pay a 2.5% royalty on the first 100,000 barrels of oil each well we produce, which means we have a 97.5% net lease. That allows us to generate much higher rates of return than paying a 20% to 25% royalty to landowners down in North Dakota.

OGFJ: Are your Bakken assets living up to your expectations so far?

GE: The Williston Basin is one area that we're continuing to build acreage positions and actively drill. We made a large acquisition in May from Baytex Energy -- $311 million, which was mainly existing wells and acreage in Divide County, North Dakota. Today we have about 132,000 net acres, of which 92,000 is in North Dakota and 40,000 is in the Tableland Field. So we have more than 800 drilling locations in the middle Bakken and Three Forks-Sanish and five to seven drilling rigs running at any given time. That is a lot of future drilling.

OGFJ: Are you having any infrastructure problems with getting your product to market?

GE: In the Tableland Field, we take our crude to a central battery, and it's pipelined into Enbridge. The pipeline goes directly across our property, and there is a refinery up there in Saskatchewan. The North Dakota production is being sold at the wellhead, and it's trucked to a railroad. We haven't had any issues on getting our crude out. As you probably know, over the last 60 days, the basis differential for Bakken-Three Forks crude has changed dramatically. We're now getting about a $2 premium over WTI.

OGFJ: The Eagle Ford is one of the most talked-about oil and liquids plays in North America. Do you view it as one of your core assets?

GE: I would say that of all the shale plays we're involved in, the Eagle Ford is the most mature for our company. We have more than 30 wells drilled and producing in the play, and we have a defined acreage position there. We have 26,000 net acres, and it's been very difficult adding new acreage because the cost is so high due to the high degree of competitiveness. We have another 200 wells we can drill, but frankly we would consider divesting our holdings in this play for the right price. We're exploring this possibility right now and have this particular property in a data room with an investment bank, and we're talking to a number of different parties. It's not something we have to sell. It's not something we're being forced to sell. It's just that we see our upside as being defined. We've done about as well as we can do in this play with some of the highest producing wells throughout the entire Eagle Ford Shale. We've made significant improvements in the well completions, it is a "well-oiled machine", and it might be better suited for someone with a lower cost of capital.

OGFJ: Have you had any issues with bottlenecks with regard to gas processing in the Eagle Ford since there is so much volume coming onstream right now?

GE: We're predominately crude oil. We're 85% oil in the Eagle Ford, so we don't have any of the issues that gas-weighted companies might have in the play. There's never been a day since we've been involved in this play that we've had an issue getting our oil or our casing head gas sold once tied into pipe. We're currently producing about 3,000 barrels of oil per day in the Eagle Ford. It's sold at a $10 premium over WTI prices. It's sold under what is called "Louisiana Light," and if the WTI price is $90, we get $100 for our oil today due to the basis premium.

OGFJ: Magnum Hunter is also active in the Pearsall play in South Texas. What can you tell us about your operations there?

GE: The Pearsall shale underlies the Eagle Ford and is about 1,500 to 2,000 deeper. It's still very early on in this evolving resource play. We bought some acreage there and we have just drilled our first Pearsall test well. To a large extent, the jury is still out on the Pearsall. Cabot Oil & Gas has been successful in convincing others that this is a great new play. They recently announced a transaction with a foreign entity on their acreage located near us. So we're still looking at the Pearsall as an emerging play but it is getting more interesting by the day.

OGFJ: Is the Pearsall a liquids-rich play?

GE: We believe it's going to be more gassy with condensate. The negative side of it is that we believe the gas is going to have some H2S associated with it, so there will have to be specialized processing facilities. Fortunately we bought a company back in May through our midstream division, TransTex, that is a specialist in this type of processing, so we think we have a competitive advantage in this area.

OGFJ: Magnum Hunter issued a press release recently saying that you are curtailing natural gas production in the Appalachian region. Can you elaborate on this a little?

GE: We have short-term curtailments in Appalachia in two areas. The curtailments in the Marcellus aren't voluntary. Those are due to processing restrictions from Dominion Transmission, which is who we sell our gas to at this time. Those should be alleviated in about a month when our new processing plant that is being completed by MarkWest Energy Partners goes live. So that issue will go away. However, we have voluntary shut-ins of about 400 gas wells that are predominantly producing from the Huron formation over in Kentucky. The reason for those shut-ins has to do with low gas prices, some higher transportation charges, and the fact that the summertime requires us to buy some other chemicals to reduce the ethane to make it pipeline qualified. Since it would cost us more money to produce than we were making, we made the decision to shut in those wells. But as the weather cools, the ethane is much less a problem, and those wells will go back on before the end of the year. Especially since gas prices have dramatically improved.

OGFJ: You have about 60,000 acres in the Utica Shale. Tell us a little about what you're doing there.

GE: Most of our Utica assets have come as a result of acquisitions. We tend to buy a lot of production in the shallow formations, and with that comes a lot of Marcellus and Utica leases. That's good from the standpoint that almost all of our acreage positions are held by production and cost very little on a per-acre basis. We've been watching and learning from others that are drilling around us. As we monitor the activity, it turns out that it appears we are in a pretty good sweet spot. We're excited about our holdings, and we're planning to drill our first Utica test well early in the first quarter of 2013. We may drill up to 10 Utica wells next year.

OGFJ: Where in the Utica are your assets?

GE: We're in three counties in Ohio – Washington, Noble, and Monroe – and in Tyler County, West Virginia.

OGFJ: Eureka Pipeline, Magnum Hunter's midstream subsidiary, has proven valuable to you given your early entrance into a number of plays lacking infrastructure. How does your midstream business complement your E&P segment? What are your long-term plans for the midstream segment?

GE: When we bought Triad Energy out of bankruptcy back in February 2010, we also ended up with lots of right-of-way and some midstream assets, which we have since rebranded Eureka Hunter. We have now built over 60 miles of new 20-inch pipe, predominantly in West Virginia to gather Triad Hunter's new Marcellus wells. We're moving about 70 million cubic feet per day. We're now laying that pipe under the Ohio River to go from West Virginia to Ohio, which should be completed in the next 30 days. It will allow us to begin gathering gas in the state of Ohio. So we're pretty excited about what we've been able to accomplish with Eureka Hunter Midstream, and our goal is to spin this out to the public sometime in 2013, probably about mid-year. We have brought in a private equity fund, ArcLight Capital Partners out of Boston, and they've invested about $130 million. They own over 30% of Eureka Hunter. While it's early in our life cycle, we are building the system out and significantly increasing volumes will occur as the new MarkWest facility that I mentioned earlier comes on stream in late November.

ND Pump Jack

OGFJ: Do you operate midstream assets elsewhere or just in the Appalachian region?

GE: In May of this year, we bought a group of 60 small amine and gas treating plants through a company called TransTex. That gives us diversity as well as significant plant capacity and knowledgeable manpower in gas processing throughout the state of Texas. As we introduce TransTex Hunter to the Appalachian region, they're looking at deploying new assets up there.

OGFJ: Magnum Hunter is obviously a resource-rich company, and yet your stock is currently trading at a discount to others in your peer group. What are investors missing?

GE: The market today rewards those companies that use less leverage. We aren't shy about borrowing, and with my finance background I am comfortable and always looking at our existing and future cash flows. If we were to monetize some of our assets, such as the properties we own in the Eagle Ford, that will likely get some attention from the marketplace and could be a real catalyst for us. We recognize that we need to do some things to harvest a lot of the potential that we have built over the past few years. If we do, maybe the market will take note. We're very happy with the asset base we've built, but we're not so happy with the share price. We've always felt that time would take care of that issue as long as we continue to perform as we have done in the past. And that's the path we are continuing down.

OGFJ: Which of your assets looks the most promising right now, and where do you plan to concentrate your capital spending in 2013?

GE: The Marcellus will get a big chunk of our budget next year. We've got the pipeline in place and running. We've got the processing plant almost operational. We have already delineated our acreage position. We're in the process of taking delivery of a new drilling rig for this region. We've got everything in place, and gas has moved back from $2.00 to around $3.50. This is encouraging. Of all the shale plays we're in, the Marcellus decline curve has outperformed even what our petroleum engineers estimated. This means that even though we've held back drilling in this region in 2012, there has been an amazing resilience of existing production holding up. If we had stopped that drilling in other regions, we would have seen a dramatic decline in production. We haven't seen that in the Marcellus. This tells me that we're probably underestimating our recoveries per well and field-wide. For the next 12 months, I believe we'll be in a $3.50 to $5.00 gas regime, and with that price environment, we can make an incredible rate of return up in the Marcellus. I don't think any other gas field in the United States can profitably compete with this scenario.

OGFJ: We appreciate your time. Thank you.