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Original Source: FD (FAIR DISCLOSURE) WIRE
OPERATOR: Welcome to Devon Energy's Barnett Shale resource update.
At this time all participants are in a listen-only mode. After prepared remarks, we will conduct a question-and-answer session. This call is being recorded.
At this time, I would like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.
VINCE WHITE, IR, DEVON ENERGY CORPORATION: Thank you and welcome, everyone.
Thank you for participating in today's webcast. For those of you listening by telephone, if you've not already done so, you can access the slides that accompany today's presentation from our home page. That address is www.DevonEnergy.com. We will also make a replay of today's webcast available this afternoon on our website.
In today's call we're going to make many comments about our plans, forecast, estimates and expectations for the future; and under U.S. securities laws such comments are considered to be forward-looking statements. Whenever we make a forecast, we strive to provide you with the very best information possible; however, you realize there are many factors that can and likely will cause our forward-looking results to be different from the forward-looking statements.
We encourage you to review the investor notice on slide two of today's presentation as well as the Form 8-K we filed on February 6, 2008. That 8-K covers our estimates for 2008 and also has a review of risk factors that can influence Devon's actual results. I'll remind you that we may make reference today to some non-GAAP performance measures. When we provide those measures we are required by securities law to provide certain disclosures about the relevance of the non GAAP measures and those disclosures have been posted to our website.
Following the prepared remarks, we'll respond to follow-up questions. We're going to limit the meeting today to about two hours; and with those items out of the way I'll turn the call over to our President, John Richels.
JOHN RICHELS, PRESIDENT, DEVON ENERGY CORPORATION: Good morning, everyone.
Larry Nichols and I thank you for tuning in for today's presentation. The purpose of this conference call and webcast is to discuss with you the potential of Devon's resource base. Devon's technical teams follow a rigorous and disciplined approach to assessing our potential; and today, for the first time in Devon's history, we're going to share our approach with you, as well as our current view of the Company's overall resource potential.
We will not be modifying our production forecast for 2008. We remain comfortable with our previously provided forecast of 240 to 247 million equivalent barrels. What we will be giving you is a detailed look at our current view of Devon's long-term growth potential from our existing resource base, and a sense of how we approach capital allocation.
The bulk of the presentation will be provided by our Senior Vice President of Exploration and Production, Steve Hadden, with a wrap-up by Larry. We also have with us today a number of other Devon officers and we will all be available to answer your questions at the end of the presentation. Before I turn call over to Steve to talk about Devon's resource potential, I want to remind you of the philosophy that has driven the investments behind the Company's assets. Those of you that know Devon are aware that for six or seven years now, in addition to the short cycle time exploitation and development projects that have driven our performance, we've been investing to establish a pipeline of longer term growth opportunities.
Our goal was to build Devon into a company that could deliver sustainable, profitable growth over the longer term entirely with the drill bit. We believe that we've achieved that goal. As Steve will outline, Devon's resource base represents the best of North America. From the Oil Sands of Western Canada, to the deepwaters of the Gulf of Mexico, Devon has established significant positions in the most promising growth areas of North America. This is complemented by a focused position in two high potential international exploration areas, offshore Brazil and offshore China.
While Devon's approach to growing production has changed over the last decade, our overarching goal has not. We are driven to establish sustainable growth in production per share on a debt adjusted basis. Rather than maximizing top line growth, we're focused on optimizing our per share growth by balancing our exploration and development budget against share repurchases and debt levels. In addition, our capital expenditures are focused on those projects that can deliver the best full cycle returns. This is because we believe that in order to deliver sustainable growth, we must grow profitability as well as production.
Now to talk in more detail about the assets that are driving Devon's growth, I'll turn the call over to Steve Hadden. Steve?
STEVE HADDEN, SVP OF EXPLORATION & PRODUCTION, DEVON ENERGY CORPORATION: Thanks, John and good morning, everyone.
I have the great pleasure to describe for you the potential of Devon's asset base in some detail. As John mentioned, it's a broad and very deep platform for sustained growth. I'm going to start with the Barnett Shale, and then we'll move to the rest of Devon's extensive portfolio of opportunities in the second half of the discussion.
Slide five shows the Barnett Shale regional setting, just to refresh everybody. It sits in the North Central Texas and is the largest gas field in Texas, producing 3.5 BCF per day equivalent currently from the play. Now, that's approaching 7% of the U.S. domestic gas production. So a huge field, a world class field with about 8,000 wells in it, covering about 10 counties.
Slide six shows a comparison of the U.S. shale, some of the U.S. shales, including the Woodford, the Fayetteville, Marcellus, and Barnett Shale. You see its thickness and most importantly its total gas in place, 147 BCF per square mile which is nearly double or at least double of the rest of the shale positions. It really makes it stand out as best-in-class. That in concert with the relatively low above ground risk characterized by being next to one of the largest gas markets in the country in the Dallas, Fort Worth area, the topography which is really gentle prairies and a very--in a very favorable producing state, Texas and a good, strong, regulatory environment; it makes its execution risk relatively low in the Barnett, so just a best-in-class shale.
If you look at slide seven, we've shown you now the industry horizontal wells drilled from 2000 to 2007. That's about 4,200 wells so far that have been drilled in the field. The slide shows wells shaded by their estimated ultimate recovery. If you note on the footnote, the estimated ultimate recovery was calculated using public data from IHS, which is readily available and really standardized hyperbolic decline analysis to come up with those EURs.
The red wells represent EURs, the best wells in the field, between 1.5 to as much as 15 BCF equivalent EUR. The yellow wells represent the range from about 1 to 1.5 BCF equivalent, around then the blue wells represent the poorer wells in the field from 0 up to about 1 BCF equivalent. So that shows the horizontal well drilling activity and you can see the cluster of the higher performing wells in the red.
If you move to slide eight, you see that we've now characterized those clusters by drawing outlines. The first outline is a red outline that shows the--what we call the primary development area of the Barnett Shale now. You can see on the right hand chart that primary area is characterized by very strong EURs, again, the best wells in the field. It's also characterized by high repeatability both in the well results, but also in the economic results in those opportunities; and you can see that industry has drilled 3,700 wells within the primary development area of the Barnett Shale.
You see the area between the red and the blue outline that we've termed the emerging development area where you have wells that are approaching a BCF on average, but we see continuous improvement in that area as we and others in industry derisk that aspect of the play. So we see improving repeatability, improving economic results, and well results in that emerging area.
Finally, when you look outside of that blue outline, you see the area we've termed the speculative area. This area is characterized by the least amount of drilling, relatively low EURs and recoveries, and has a high degree of uncertainty and variability; both from a well results standpoint and from an economic standpoint.
So that characterizes the Barnett Shale. You also see a gray area on the right-hand side there. That represents the highly urbanized area in the city of Fort Worth that has quite a bit of challenges as it relates to the above ground risk that I talked about earlier with obstructions, large density of population, more costs, and just quite challenging.
If you move to slide nine, we want to show Devon's position, and Devon's position is shown in the yellow. That's our least acreage shown in the yellow and it really illustrates Devon's very superior first mover position. That first mover position has done several things. Number one, it's given us a very strong position in the very best part of the field. I'll also talk a little bit later about having an economic advantage, a value advantage, and a volume advantage from that first mover position that Devon and its predecessor company, Mitchell, were able to gain and sustain to this day.
You see that Devon's acreage is highly concentrated in the primary development area, the best part of the field. We have 527,000--over 527,000 acres there. We also have 121,000 acres in the emerging area, with 78,600 acres in the speculative area. Now, that 78,600 is mostly held by production in the speculative area and it represents only about 11% of Devon's total acreage position. Now, if we look at how we accomplished that position, as I said before, it was a great first mover advantage by Devon and that's shown on slide 10.
If you look at slide 10, you see the history of firsts that Devon continues to realize after its acquisition of Mitchell Energy. In 2002, we were the first to drill the horizontal well program in the Barnett Shale. It was the Veal Ranch 1H well and it was drilled in August of 2002. We were also the first to drill a horizontal well in Johnson County. That was the Sandifer well number 2H in February of 2003.
In addition to those firsts, in 2005 we were the first to drill an 80 acre surface acre location or 1,000 foot spaced horizontal in-fill well in the play. In 2005 we were also the first company to reach 1 TCF equivalent of net cumulative production. In 2007 we were the first to drill a total of 1,000 horizontal wells.
We're way above that now, probably approaching 1,300; and in the second quarter of 2008, we will reach 1 BCF a day equivalent net production to Devon, and I emphasize net production because that's what Devon can deliver to its shareholders. Gross production, some folks comment on gross production. Gross production does not reflect what can be delivered to the shareholders. It's--essentially has to be affected by your net revenue interest or your royalty burden and your working interest for the play.
So that BCF a day, net production goal or accomplishment and the 1 TCF net equivalent cumulative production is yet untouched by any of the other competitors in the field as far as attaining those firsts. And that BCF, if you remember, we achieved--we set a goal out just about a year ago, little over a year ago, to achieve 1 BCF a day net production by the end of 2009. We've now delivered on that goal, 18 months early.
Slide 11 continues to show Devon's first mover advantage in how it begins to translate into value, a real value advantage. This chart shows acreage leased in the yellow bars-- net acreage leased by Devon and this is leasing activity. Other than the pre-1998 bar, which shows you the held by production position that Devon and its predecessor company held in the play before 1998, 350,000 acres and that was held at very favorable royalty rates.
As you look through 1998 through 2001, you see that's the period of time where Devon leased the majority of its position and that was a period of time where royalty rates were very attractive and our net revenue interest as a result is relatively high at about 81% in the play. After 2001, that was a period of time when competition began to move more and more into the play. Royalty rates began to go up; lease bonuses began to go up. And you can see, Devon was able to trim its lease acquisition through that period of time and still retain that economic advantage and build that very high net revenue interest.
The next slide really shows you, slide 12, shows you the value advantage that that gives Devon. If you look at the bar on the right, these yellow bars represent before tax MPV-10, calculated on a model well. So the well you see in the notes at the bottom, it's an EUR of 2.2 BCF, drilling completion cost of $3 million and a price of 750 per MCF, flat, and each of these are calculated on the same well. The thing that changes are the leasing terms. You see that Devon has achieved the position of 81% net revenue interest at a cost of $2,800 per acre.
Now, that cost includes the cost of the Mitchell acquisition, the Chief acquisition, and our leasing cost; and during that period of time we were leasing, we were leasing that acreage at an average of about $300 an acre. As I mentioned before, after 2002, competition began to ramp up and we saw less favorable terms as far as royalty burdens and bonuses and those are shown in the 75% NRI bar and the 70% NRI bar.
If you note the value shown at the top in MPV, Devon's position on an identical well on Devon's terms, we deliver more than twice the value of the 75% NRI positions and more than four times that--or nearly five times that of the 70% NRI position. So the first mover advantage not only gives us the best position in the field, it also delivers a real value advantage to the Company.
If you look at slide 13, you see Devon's Barnett Shale net production in our history since the acquisition of Mitchell in 2002. This chart shows the vertical development where we rapidly ramped up the heart of the field through 2003. We then began to derisk a larger part of the field through horizontal drilling and the leadership that we showed there that I mentioned earlier, as well as the seismic work and reservoir characterization work that we did throughout the non-core area, what was termed as the non-core area then of the field.
Once we accomplished that derisking, you see we get very high repeatability and very good development and over a period of about less than two years, we've nearly doubled the net production to Devon's interest in the field, hitting that BCF a day production number I mentioned earlier, which is about 2% of the total U.S. domestic gas production.
Slide 14 shows gross operated volumes for comparative purposes. As I mentioned before, gross can be a bit misleading because you have to apply working interest and your net revenue interest to determine what can actually be delivered to your shareholders; but in Devon's case, we've shown you that Devon's net and gross is very close. That's not necessarily the case for other companies. But that being said, using public data from IHS, we are more than nearly double the next closest competitor in the field, Chesapeake, and more than double the fourth largest competitor in the field on a gross volume basis, which is EOG. So again, the volume advantage of the first mover becomes very, very obvious in this slide.
On to slide 15, the Barnett Shale delivers outstanding reserve growth. Not only do we deliver that production growth but as you look to the future, we've identified the reserves and have the potential in the ground to continue that growth for a very long time to come. The compound annual growth rate for our reserves just since 2004 through 2007 has been 31%.
If you see on the right, since we acquired Mitchell in the--in 2002, we had booked 1.8 TCF at the time of the acquisition. We now have 4.3 TCF of reserves and that's despite producing the 1.3 TCF of production that we show on the chart on the right. We've added discoveries and revisions of 3.2 TCF equivalent just to the proved base and we've acquired Chief which added 0.6 TCF to the total; but really added a lot of running room that you're going to see in this potential that we'll show you here in just a minute. So again, the first mover advantage turns into an advantage on value, volume, and production and in reserves, and in future growth.
Slide 16 simply makes the point that that proved picture is just the tip of the iceberg. Our proved reserves are 4.3 TCF equivalent, a huge number in of itself; but below the surface lies the huge potential of Barnett Shale and that's what we're going to take you through right now.
If you look at slide 17, before we go into what the numbers are, we want to tell you how we developed the numbers; and the framework that we used to classify the resources of not only the Barnett Shale, but of the entire company's asset base. We used a …