EXECUTIVE Q&A: Joseph A. Reeves and Michael J. Mayell

In 1981, Joseph A. Reeves Jr. and Michael J. Mayell became partners and formed Texas Meridian Resources Inc., an independent oil and gas producer that was renamed Meridian Resource Corp. in 1997. Reeves, Meridian's chairman, and Mayell, its president, discussed the company and its future in a Nov. 3 interview with Sam Fletcher, senior oil and gas writer for OGJ Online.

Sam Fletcher
OGJ Online

In 1981, Joseph A. Reeves Jr. and Michael J. Mayell became partners and formed Texas Meridian Resources Inc., an independent oil and gas producer that was renamed Meridian Resource Corp. in 1997. Reeves, Meridian's chairman, and Mayell, its president, discussed the company and its future in a Nov. 3 interview with Sam Fletcher, senior oil and gas writer for OGJ Online.

OGJ Online: In 1997, you acquired Cairn Energy USA, in a $212 million stock transaction. Then the next year, you acquired essentially all of Shell Oil Co.'s onshore oil and gas properties in south Louisiana through another stock swap that substantially increased the size of your operations. How did that come about and how has it helped position Meridian Resource for the current upturn?

Reeves: When you're bent toward exploration like we are, you have to access a lot of capital and you have to access the development of a lot of projects or prospects to replace reserves with. That's just the nature of our business. We're a depleting asset on an ongoing basis.

When we reached that crossroads with the need of additional capital to continue the program�as successful as the company was in exploration, with greater than 70% success drilling�we could see down the road that the future was based on how many projects that we could develop and how many plays we could extend into the south Louisiana region. That required a lot of seismic costs, expenditures up front, as well as a lot of man-hours in time.

So we begin to look around for companies that had solid production but also mostly exploration opportunities. Cairn was one that came to light. It's always easier to buy somebody that's for sale than somebody that's not. They had grown their company primarily through exploration and they had done it with the use of 3D just like we had. And they were in the offshore arena, Gulf of Mexico, which was just an extension offshore from south Louisiana and South Texas where we were focused.

OGJ Online: Your operations were onshore at the time.

Reeves: We were primarily onshore. We had drilled maybe one well in a bay or something by that time. But the geology doesn't change at the coastline. Their projects were very similar to ours geologically and geophysicaly. They had good solid production, but they didn't have the capital to go forward and do either the platforms they had drilled initial wells on or development wells...without having to farm-out or lose their interests on operating agreements.

Fortunately, our balance sheet was very clean at that time. We took on the ability to drill the wells with Cairn's partners and to build the platform to bring a project. We saw what we thought was a good future on offshore projects from them.

Shell came along literally before we closed Cairn, to ask if we had an interest in purchasing all of their south Louisiana properties.

Because we were in south Louisiana, we had looked distantly at Shell's properties and all of the majors' properties, wondering which if any would be willing to sell.

We begin to look at the majors' properties because the first discovery we made was on Chocolate Bayou (in southeast Texas), which was a majors-operated field. Texaco had drilled over there; Phillips had drilled over there. We used the 3D seismic they had shot to go in and find a deeper off-structure reservoir of about 100 bcf. So the concept was in place and we felt we could carry it to south Louisiana where a much more complex and faulting geology created more opportunities like Chocolate Bayou that needed some more 3D over it.

Shell gave us that opportunity to buy a major's fields and begin to exploit those. One of the best things was that Shell had shot 3D over every one of their fields before we made the purchase. We had about 2,200 sq miles (of 3D data) and they had about 1,800 square miles of data they hadn't even looked at.

In looking back, I believe in my heart that Shell corporate had made the decision to get out of south Louisiana and used the shooting of 3D over their fields as the means to dress up the prospects and opportunities to get the maximum price.

They were using joint venture capital to shoot 3D over their fields. And naturally, it was very attractive to somebody like us in the exploration business that could come in and buy it�and buy the field in some instances for just the cost of the 3D and estimated cost of acreage and get the production as lagniappe.

When we looked for the growth step, we looked for buying a good solid base of production. But we primarily looked to see who had good growth opportunities for exploration through the drill bit. Those two provided that for us�Shell being probably the better of the two, in retrospect.

Shell explained to us that we really wouldn't have been large enough to buy their properties and they take the stock in our company, if we had not closed the Cairn acquisition.

The Cairn property was not as profitable as we had hoped it would be, or as profitable as the Shell properties are proving to be. But it was a necessary step to get to the very profitable Shell properties.

OGJ Online: How profitable have the Shell properties proven so far?

Reeves: The best example I can give you is that we drilled our first well on Weeks Island even before we closed the transaction and made a discovery of about 12 million bbl in that old field where they had drilled some 250 wells on that salt dome. We have drilled several more since then, bringing that to our No. 2 property now�it was our No. 1 property.

The Thornwell field was a new-discovery Shell property that had 3D over it but never had a well drilled on it. We brought that from ground zero to 85 MMcfd production by drilling some 13 out of 14 wells successfully.

We're continuing to see other opportunities under Weeks Island, under Thornwell lookalikes, over White Castle. We're looking to shoot a 3D survey over Goodhope, which they didn't have 3D on, but they had great structure and great opportunity.

We believe that, especially with the restructure of the Shell preferred stock and the buy-back of their stock, we more than achieved pay-out on our purchase of them through the discoveries.

Mayell: When we did the initial look in the spring of 1998, we gave Weeks Island about 49 bcf of gas. By the time that we closed, we found that it was producing pretty well and had 39 bcf left. Since June 1998, we have produced more than 36 bcf out of what we found and we have 84 bcf left. I think that's a measure of the profitability.

OGJ Online: What is your reserve ratio now?

Reeves: Our mix of reserves is probably 55:45 gas to oil. That will change probably over the next 12 months to something like 60:40 gas to oil.

Mayell: But at those ratios, we're still the most oily of all the independents of our size. Most of the others are 80:20 or even greater than that. While oil is priced in the $30/bbl range, it makes a difference (on our balance sheet).

Reeves: Being in this region, you would think our reserve life would be a lot shorter (than 7.4 years), but we have a good mix of properties without having a lot of proved undevelopeds on the books. We still have Chocolate Bayou, but everything else is either offshore or south Louisiana. Most of it is onshore in south Louisiana, in the marshes and the bay areas.

OGJ Online: You've been very active in that coastline transition zone between land and offshore.

Reeves: Right. In fact, we're working on a transaction that will give us access to more than 300 blocks of 3D data for review in the transition zone. We are looking to carry the extension from the marsh into that shallower water, less than 100 ft, and carry that concept into the Gulf of Mexico.

Mayell: What we are good at is finding oil and gas in structural traps in Miocene sands at depths of 18,000-22,000 ft, which is not for the faint-hearted. Those traps exist offshore, too, but historically they have been overlaid by so many shallow amplitudes. The people who play offshore generally have been going for the amplitudes.

The same play that we make onshore is relatively immature offshore, which means you have some greater opportunities in terms of reserve size. But it also means you have greater risks, compared to normal offshore drilling.

But those are the risks that we've pretty well been assuming all along as we've done our onshore exploration.

Reeves: In the shallower waters in the gulf, most of the plays deeper than 15,000 feet haven't been drilled yet, haven't been exploited or explored yet. People go for the low-hanging fruit, but there doesn't seem to be any left.

That's what happened onshore�we had to go deeper than 12,000 ft. Thank God for the 3D seismic that enabled us to get the resolution below those depths to discern those faults and to look for those that hadn't been drilled.

OGJ Online: How did Meridian develop its expertise in 3D?

Reeves: It was acquired. The seismic workstation became available in the late '80s. The first project that we looked at that had 3D over it was the Chocolate Bayou project. We had the geology, but we brought the geoscience to the table.

We used consultants to begin with. But then we brought those consultants inside. Then we began adding full-time people. As the majors were getting out of the domestic scene, that expertise became available from the majors. A lot of it came from Shell, initially, and those people still are here.

We like to say we begin with geology, then overlay the 3D with it, and tie those two together before we ever drill. The initial development of those exploration prospects came from the geology we had in-house. Then as 3D became available to the independents, we acquired the 3D and just built on that. We've developed probably 37 guys who work that 4,000 square miles of data and look to shooting more on a regular basis as a standard for the company.

It has worked so well for us. When you have 70%-plus success rates over a 10-year period, I think as a standard we will always have and use it.

We brought processing in house, about 5 years after, as the next extension. Previously, there wasn't a 3D that we shot that we didn't have to reprocess and use different algorithms to reduce the noise and interference in order to interpret the data.

Then instead of having to wait periods of time for outsourcing, processing and reprocessing, we had it in-house and could run it 24 hours a day.

The geoscientist could sit at the workstation and work with the geologist and decide if the data was adequate. If not, they could go directly back to the processor and ask him to reprocess it a certain way. That stops 3-6 months of delays from using outside processing contractors. That has really enhanced our ability to improve our data.

Mayell: I think one of the things that is least accepted out there is that processing itself is as important as the geological interpretation of the processed data. And there are a million ways to process the same piece of information. It's very much a trial-and-error process of what seems to work and where you go from "good enough" to "the best I can get," which is a very, very expensive product, especially if you do it outside.

But if you do it internally and it's more interactive, you can focus on making sure you get the depth range that you're looking at in the best possible shape you can get.

It's an important part of what we do.

Reeves: One thing we've learned onshore is that bright-spot technology doesn't always work. Offshore, it does work more times than not. So an offshore company typically will come on shore and try to use the same technology that they've interpreted 3D data with offshore.

As frequently as not, we've seen where dim-outs work onshore, as compared to bright spots�which is just the opposite of what you would think.

Onshore, there is a specialty in understanding the nuances of the data and what is reflective of pay. It's not a proprietary thing�it's just experience, and really an art, when you get to that point.

And the second phase of it is the ability to integrate the three disciplines of the company in one shop at the same time. Even if you hire a consultant full-time inside, he's not looking at it with an ownership position.

OGJ Online: This summer you obtained an option to repurchase all of the Meridian preferred stock and 6 million shares of your common stock held by Shell for $114 million. That option is to be exercised by the end of January, correct?

Reeves: The end of January is the expiry of the option. As soon as we can exercise it, we will�the latest will be at the end of January.

We're trying to do it where we can maximize the number of shares that we bring back into the treasury of the company so that we can increase earnings/share and cash flow/share numbers to stockholders.

We did a little private equity offering here about a month ago and raised $38 million toward that end. We've had excess cash flow that we've accumulated probably $45-50 million on, not compromising our capital budget at all for this year or next year.

We have another component of a sub-debt piece that we will put together to close it out, and then bring in a net 11.7 million shares.

OGJ Online: What will be Meridian's position after that?

Reeves: Shell will be the largest shareholder still, with about 7.1 million shares of stock. We won't have any preferred stock outstanding at that point. The capital structure will be simplified. We hope to continue to reduce the leverage. I think our projections for next year is that we'll see excess cash flows that will help us reduce our debt in cash components, rather than just by adding reserves.

Our focus will be to stay profitable, reduce the leverage and improve the value per share. Our goal is to get our debt-to-book-value ratio down to something in the 40% range.

Mayell: Basically, everything we get next year in excess of our capital budget will probably go to debt reduction. If prices stayed as good as now, it could reduce our debt by 50%.

Reeves: We recognized, when we made the purchases of Shell and Cairn, that we incurred more debt than we intended to, ever.

Mike and I are debt-adverse people. We recognize what debt can do to a company's perception in the market place and its ability to capitalize a program or survive during downtimes. So we're very focused on reducing the leverage in the company.

We can do that in a couple of ways: One, find more oil and gas, and, two, pay down debt with excess cash flow. We've been blessed with good cash flow this year, better than any in the company's history.

That's because we've had higher production averages this year, which is anomalous among independents. We see reports every quarter of declining production rates by our industry, which is indicative of why prices are going up, in my opinion. Higher decline rates and less replacement of reserves, as well as higher demand, are driving the price up where it is.

We have used that (extra cash flow) to improve the fundamentals of the company and to buy out the Shell overhang in preferred stock to eliminate that question mark about how much dilution would be impacted if they exercised their right to sell.

OGJ Online: Where do you see the company going from today? What are your plans?

Reeves: We have an inventory (of prospects) that I believe is second to none that we've had in our history because of the acquisition primarily of the Shell properties and of bringing to that ready-to-drill stage some of the exploration projects that we are about to start.

We will continue to look to prospecting for our primary growth. But we continue to look for opportunities to buy companies or production that have associated production with it to grow the company.

That's not necessarily to say we're out to merge with someone again because those things become very painful and it takes a long time to digest them. But if there's a field or a joint venture or an opportunity to do something that has an exploration component to it, where we can use 3D and our expertise to grow it, we'll look at that.

But our focus is going to be on continued development of plays in south Louisiana through the transition zone, to grow with the drill bit primarily.

Our finding and development costs over the last 2 years have averaged about 97�/Mcf equivalent. We want to keep that kind of cost down. I think the best way to do that in this environment is to find oil and gas, not to buy it.

OGJ Online: It sounds like the type of acquisitions you'd be most interested in would be properties, rather than the companies.

Reeves: That would be the preference, if we could find opportunities where somebody didn't recognize the exploration potential in a field that our geologists had developed plays over. Where we could go in and buy it for maybe the reserves remaining and the production on some multiple, but really looking at it for the exploration opportunity upside.

OGJ Online: You've had a very successful exploration program from about mid-1998, so you have a lot of discoveries that you can develop now.

Reeves: That's right. Thornwell field is one. Weeks Island is another. The North Turtle Bayou-Ramos area is a real focus for us�we had two fault blocks drilled and seven additional that we had identified. We drilled one and made another discovery this year, and we're drilling the second right now. We're encouraged by the drilling.

We're scheduled to spud at least one more out there this year, and we've got four more that we will probably drill in 2001.

At Weeks Island, we've got two wells drilling. We probably have 10 projects in the Weeks Island area that we will drill along with Stone. It's an onshore subsalt play that is highly faulted.

We're looking to get up next to the salt where Shell, with their 2D data, couldn't see the definition of the salt face. We're getting up closer to the salt, using the 3D and the drill bit to determine where the salt is relative to the pay. We are getting simply up-dip from known production�wells that have produced millions of bb�and we're finding additional 1-2 million bbl snuggled up against the salt that they couldn't see for the overhang.

And those overhangs continue down the salt face as you go, so we see a lot of exploration opportunity out there as well. It's different from anything we've drilled before, but when you can find 2 million bbl just up-dip from something Shell thought was the extreme limit, it's kind of fun.

Mayell: And where else can you do that at 5-10,000 ft in south Louisiana? It's just incredible.

OGJ Online: What was your drilling budget like this year? How many wells did you do?

Reeves: We've done 20 wells so far, and completed 16. We're currently drilling five. Our drilling budget was about $86 million to date as scheduled.

We will probably increase that, depending on the success of some of these wells that we're drilling and the capital expenditures to complete those wells. But we stuck real close to our budget because we knew we wanted to close the Shell transaction.

Next year, we'll probably increase that budget by at least 10%, maybe 12%. But we're not going to go crazy on capital spending just because (commodity) prices are high.

I don't know any company CEO that I talk to who is expanding his capital budget next year more than 10-12% either.

We know we can drill $95 million next year if (market prices) went to heck in a hand-basket. We may not be able to pay down as much debt as we want to, but we know we could get our capital budget spent. And that's what we're trying to do-stick to what we're comfortable to achieve and not plan on exponential growth in our drilling budget.

I think the industry is saying to the world, "Show me the demand is real." I'm not going to start drilling twice as many wells every year just because the price has gone up.

OGJ Online: Do you see drilling costs rising?

Reeves: Yes, we do. We're seeing that already. Land rig rates have gone up from $7,500 to $12,500/day just here in the last 3-4 months. Barge rigs have gone up from $14,000-$15,000 to $22,000/day. Those costs are growing.

One good thing that we've got with five wells drilling, we've got three barge rigs and two land rigs that we're working. And once you latch onto a rig, you're able to keep on drilling with it.

We've got rigs available to us to keep the program moving from one well to the next, which is why we'll be drilling or spudding eight wells in the next 6 months. There are people who don't have rigs available to them right now, and they are very difficult to get.

We went out looking for a new rig the other day and found it, but we had to make a lot of phone calls and do a lot of begging to get it.

OGJ Online: That demand is stimulating some contractors to bring their stacked rigs back into the market.

Reeves: One thing about that, that we've experienced up close and personal on one of the wells we just drilled (with a rig brought out of mothballs), is the new crews out there. What would normally have taken 45 days to drill took 75 days to get down. And they got stuck I don't tell you how many times�twisted off 400 ft in the hole, 80 ft from the bottom, and had to fish for that whole string with the prospects of having to just drill us another well.

Fortunately for us, it was a turnkey (contract). That's one of the things we really have gone to. We don't get it every time, but we almost insist upon when we can. We're not going to repair those rigs on our time and we're not going to train crews on the job, but we will do a turnkey.

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