PDC Energy's CEO Hosts Analyst Day Conference (Transcript)

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PDC Energy, Inc. (NASDAQ:PDCE)

Analyst Day

April 04, 2013 1:00 pm ET


James M. Trimble - Chief Executive Officer, President, Director and Member of Planning & Finance Committee

Barton R. Brookman - Senior Vice President of Exploration & Production

Scott J. Reasoner - Vice President of Western Operations

Dewey W. Gerdom - Chief Executive Officer

James A. Lillo - Vice President of Engineering & Technology

George B. Courcier - Vice President of Marketing & Midstream

Gysle R. Shellum - Chief Financial Officer

Lance A. Lauck - Senior Vice President of Corporate Development


Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

David E. Beard - Iberia Capital Partners, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Raymond J. Deacon - Brean Capital LLC, Research Division

James M. Trimble

Okay, well, everyone, thank you for your interest in showing up today for the PDC Spring Analyst Meeting. And I especially appreciate all your support. We've had a very good year and we're here today to tell you about the results.

Remind you, if you would, to please silence all cellphones, put them on vibrate or whatever. We are doing a webcast today. So for that, it's a lot better if we don't have any ringing. Also, because of the webcast, if you hold your Q&A until the end of the session and then we'll do a Q&A. At the Q&A, if you would, please I'd ask you to -- we'll have mics that are going around, so if you can wait until that point. State your name, company and then your question. It will prevent us from having to restate it.

We'll just say that today, we are going to give you quite a bit of forward-looking information, and so I would just draw your attention to our safe harbor language at the beginning of our presentation.

The agenda for today, we're going to have -- basically, it's going to be a very detailed -- Bart's going to come up in a minute and kind of give you an overview of the operations. Scott Reasoner then is going to talk in pretty detail about what's going on in the Wattenberg Field in the Utica. Dewey Gerdom is going to get up and talk to us about the Marcellus. Jim Lillo is going to talk to us about the reserves and the -- what took place at the year end. We'll have George Courcier who will talk to us about our midstream and marketing, followed by Gysle who will give us some financial outlook and guidance for '13. Then we're going to have -- Lance is going to talk a little bit more about corporate planning and outlook and how '13 looks going into '14 and '15. Then we'll follow up with Q&A at that time.

A couple of things I'd like to do. I'd like to recognize that today, we have quite a few of our board members present and we have Jeff Swoveland who is our Chairman, a non-exec, is here today. Joe Casabona, Tony Crisafio, Larry Mazza and David Parker are all present in the audience.

Also today, besides the people who will be doing the presentations up here with me as well as on the front row. Then I'll also just mention, because most of you will be dealing with -- Mike Edwards has joined our team, reporting to Ron, as the new Director of IR. I know quite a few of you already know Mike, but we'd like to welcome him to PDC.

I think that with that, this slide, it gives you a company overview. I'm really not going to go through much of the numbers today because what everybody's going to be talking to you are the numbers and how we got to these numbers, the benefits for 2012 that we achieved. And at this point, I would like to just say, I want to thank all the employees at PDC because they are the ones who did all the work to guide us to this point. The management team gets to stand up and tell you the good results, but the work's all done by the others.

So with that, I'm going to turn it over to Bart to dive right into the operations.

Barton R. Brookman

Thanks, Jim, and hello, everybody. Today, I hope the team and I can really provide some additional clarity on what I consider outstanding opportunities for the company really in 3 major operating areas. Let me just give a quick overview of those for you.

First is the Wattenberg in blue, really our crown jewel right now, an area we expect to produce approximately 5.5 million barrels in 2013. Our drilling operations here are running in the northern and northeastern portion of the field, where we're achieving 70% to 80% liquid-rich results. In the core Wattenberg, we have 99,000 net acres. And again this is in the core portion of the Wattenberg Field, which is 95% held by production, giving us tremendous operational flexibility. You should note, the 99,000 acres is after the sale of Krieger.

In the Utica, we're very proud we've accumulated 46,000 acres. PDC expects to produce just under 400,000 barrels equivalent in this project in 2013.

And then in the Marcellus, in Appalachia, we expect just under 1.4 million barrels production net to PDC within our PDC Mountaineer JV. Our acreage position in the Marcellus is currently 125,000 acres, which is primarily, I believe, 97%, 98% held by production. I should note that 125,000 acres is a reduced number from what you saw previously for a variety of reasons and Dewey is going to cover that in more detail in a moment.

Let me touch on some of our accomplishments in 2012. We're very pleased the company has transitioned to 50% liquid commodity mix. Currently, we have an outstanding portfolio of both liquid-based and natural gas-based projects, both drilling and refracs. Our inventory of total projects now consists of 4,700 highly economic projects across 3 operating areas, again drilling, primarily horizontal drilling, and refracs.

As we committed to you a year ago, we have fully delineated the horizontal B bench from the Niobrara in our acreage and we have early data for you today on our A and C bench results.

We successfully launched the horizontal Codell program in 2012. We currently have 8 Codell well lines online, and Scott will give a lot more detail on this in a moment.

Late last summer, we began our downspacing efforts in the Niobrara and the Codell. This was achieved from pad drilling. Again, Scott will discuss early production data and results for our downspaced pads later in the presentation.

We successfully integrated a significant acquisition in the Wattenberg Field. In the Utica, we acquired our 46,000 acres as the year progressed and drilled our first 2 horizontal wells in Guernsey County with IPs of 1,800 and 2,200 barrels of oil equivalent per day, respectively. And then in the Marcellus, we improved the delineation and the reserved bookings within this project. We're currently very focused on cost optimization and our cost structure as we returned to drilling in that basin.

Overall, in 2012, and Lance will expand on this a lot more at the end of the presentation, the company

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4% overall. This ongoing liquid focus is a direct result of the technical advancements in the Wattenberg Field, appropriate capital allocation to our best project, last summer's acquisition and in 2013, will be complemented with our Utica production. What does this shift in liquid mix mean for the company's gross margin per unit?

You can see between 2009 and 2013, PD expects to more than double our gross margin per barrel of oil equivalent. In 2012, you can see a slight drop in spite of our strong focus on this liquid development. We did see a downtick in this measurement given the extremely low gas prices we experienced during that year. But overall, in 2009, you can see $15 -- just over $15 a barrel and we anticipate nearly $40 a barrel gross margin in 2013. I should clarify, this number excludes gains on hedges, both oil and natural gas.

The next slide is designed to give an overview of the organic investment opportunities that exists for PDC. Three major operating basins and 3 leading horizontal plays in the domestic U.S.: The Wattenberg, the Utica and the Marcellus. In the Wattenberg, an opportunity for up to 2,000 horizontal projects, approximately $6 billion in investment opportunities with outstanding returns.

In the Utica, we've estimated 200 locations based on 1,000 foot spacing and anticipate just under $2 billion worth of investment opportunities within this basin. Our acreage is in a liquid-rich window and should provide somewhere between 50% and 80% overall liquid mix.

In our Marcellus, approximately 600 locations of which about 360 are in our core technical area, and Dewey will touch on this in more detail in a moment, $2 billion net investment opportunity within the PDC Mountaineer JV. You can see in total, 2,800 horizontal drilling projects approaching $10 billion of investment opportunity for the company.

Just a little reflection on how we've changed and technically evolved over the last 3 years. Although PDC had prior horizontal drilling experience across many basins, you can see in 2010, we began the major transition to total horizontal drilling as a company. The company at that time was focused on vertical drilling. We've considered ourselves to be outstanding at vertical drilling, tight rock completions with an emphasis on multistage hydraulic fracturing. We quickly moved the company to a more capital-efficient horizontal drilling focus while we capitalized on our completion expertise. And in 2013, we expect 95 horizontal wells to be drilled, with just over 1,200 frac stages that will be executed by our completion teams.

Some production highlights for 2013. As shown in the graph, we expect quarter-by-quarter growth in production as we go through the year. We anticipate a solid jump, as you can see, in the fourth quarter, a direct result of adding the third rig in the Wattenberg, which should begin contributing to production in the third quarter, most likely to late third quarter, as well as the midstream startups in the Wattenberg, which should also occur some time in the third quarter. Most importantly, expect strong liquid growth in the fourth quarter as represented by the jump in the blue portion of the bar graph.

So major events to note as we go through the year. First is the LaSalle gas plant startup in the Wattenberg, which should be in the fall of this year. We expect substantial contribution from our horizontal Codell program and Scott will touch on this a lot more in a moment.

Production contribution from the third rig in the Wattenberg, which will be deployed in May, will begin in the third quarter. We anticipate first MarkWest gathering sales on our Northern Utica acreage to be in June. In the southern acreage in the Utica, we expect our first delineation well will be drilled this summer, with sales to occur -- first sales to occur sometime in the third quarter. And now that we have reestablished drilling in the Marcellus, expect the direct production contribution from that drilling to also occur in the third quarter. Overall, the first quarter level of production to the fourth quarter level of production is a 38% growth rate.

Quick overview of production by area. Again, Wattenberg, our biggest producer, at 5.5 million barrels. In the Utica, I am happy to announce, we recently had first sales in our Detweiler well into a temporary solution on the midstream, and George is going to touch on this in a lot more detail. But in the Utica, we expect first sales in the MarkWest in June as I noted and a total production of just under 400,000 barrels equivalent. And in the Marcellus, nice production growth of 1.4 million barrels equivalent.

As shown in the pie charts, 2013 production should be 54% liquids and 46% natural gas, generating greatly improved margins as shown on the prior slide. You can see the breakout of the oil being 39% and NGLs being 15%. Last is the bar graph, gives you total production mix by basin, Wattenberg and Utica being our liquids-rich basins and Appalachia being our dry gas basin.

Quick update on the CapEx. Our budget was recently adjusted for additional drilling, approved our Board of Directors a couple of weeks ago. We currently expect a total of $386 million total capital budget for PDC Energy and $57 million within our Mountaineer division on Marcellus drilling. $272 million will be spent in the Wattenberg Field on drilling and completion work. We expect to spud 69 new drills and conduct 48 refracs in 2013. And $77 million will be spent on drilling and completion on our Utica project for 11 overall spuds. $37 million will be spent on leasehold, miscellany and exploration projects. This does include some bolt-on acreage acquisitions in our Utica project. And then in the Marcellus, again, $57 million net to PDC within the Mountaineer division. This is for a total of 15 Marcellus drilling projects.

And my last slide is just to talk about the lease operating expenses for the company. You can see modest improvement, as expected, in 2013 to $4.88 per barrel oil equivalent. Total LOE, you can see, is declining to $35.4 million after the sale of the Rockies gas assets. But most important on this slide is the bar graph in the lower right-hand corner, and let me see if I can explain this.

For 2012 actual and 2013 forecast, the blue represents lifting costs related to the company's vertical production per BOE. The brown portion of the bar graph shows a lifting cost for our horizontal development at $0.60 per BOE. As we continue to drill primarily horizontal wells, you can expect the horizontal production to quickly grow in proportion to the company's total production and expect strong downward improvement in this overall operating metric.

Some trends to expect in our operating costs as we go through the year, obviously, with the quarter-on-quarter growth expected to improve as we go through the year. We should continue to see some upward impacts in the Wattenberg due to the nonreoccurring costs associated with the Wattenberg acquisition last summer. We anticipate these costs should wrap up -- these nonreoccurring costs should wrap up sometime in 2014. We have an ongoing battle, increased regulatory costs that we are actually experiencing, particularly in Colorado, related to regulatory expenses. I would classify these as a modest upward pressure. But overall, expect downward motion in our lifting cost per unit as we continue to focus on horizontal drilling as our primary operating strategy.

And that's the end of the corporate overview and strategies. And I'll turn this over to Scott to talk more about Wattenberg and Utica.

Scott J. Reasoner

Thank you, Bart, and good afternoon, everyone. I'm here to discuss the Utica and Wattenberg fields and particularly point out what we have done to this point, and also inform you as to how this will be used going into the future.

I want to begin with the Wattenberg and point out where we are located. We're in the Wattenberg Field, obviously, just Northeastern Colorado is where we're situated. We're the third largest producer and acreage holder in the play. And our activity is in the horizontal Codell and Niobrara. And not long ago, we were just Niobrara, but we're sitting with Codell results today.

We have tremendous rates of return on these projects that are shown on this slide, and definitely providing with -- us with low-risk repeatable results. We've identified 2,000 locations that are in our 3P reserves, and I'm going to go into that in a little bit more detail here in a minute.

Because of the variability results outside of the Wattenberg Field, I do want to point that our acreage is almost entirely, if not entirely, in the Wattenberg Field. So we are in the repeatable portion of the field.

We have been faced with significant high line pressure, and I know many of you are aware of that. So I want to cover the DCP expansion plans for the early part of this year that are scheduled to come on, really, as Bart pointed out, in the fall of this year. The LaSalle plant located in the center of this, and I'm going to point to this if I can get this to work here. Let's see, La Salle plant is sitting right in there, with our -- and you can see our acreage position in the background in yellow. This plant is scheduled to come online in the third quarter of the year.

We also have a number of green boxes that are identified up there that are remote compressor stations that are going to put push the gas under high pressure into the various plants that DCP operates. These should help us on the outer reaches of the field where our production is most impacted. We're in the lower GOR portion of the field and those pressures are higher out there, doubling the impact on these wells. These compressors are also scheduled to be online in the third quarter with the startup of that facility.

The facility remains on time and this is a very good news, as you can imagine, for our production. And really, we're looking at it starting and being stable in the fourth -- early in the fourth quarter.

Also I want to point out 2014 plans, which is the Lucerne plant and it's sitting right in that point right there. It's scheduled to come online in the fourth quarter. And you see in the blue box is up there, the compressor stations are also remote compressor stations that are scheduled to come online, once again, benefiting us in the far reaches of the field.

We continue to work closely with DCPs so that we align with their work. And we also know that they have a scheduled 2015 plant that's going to come online, and George will do this more justice in a few minutes.

This shows our budgeted production by quarter for Wattenberg. Bart has already shown you a similar data for the entire company. Please note the step increase in the fourth quarter and that is associated with the production from the third rig starting up, as well as the DCP facility is up and running steady is what I would say there. I know they're going to start in the third quarter, but we'll, obviously -- there are times when it takes a little bit of time to get that equipment up and running.

And I want to cover the formations that we're active in just briefly. And I know many of you are familiar with them, so this will be quick. But the Niobrara and Codell formations underlie all of our acreage, and we are operating at depths between 6,200 to 8,000 feet [ph], drilling 4,000-foot laterals and completing them with 16 stages typically. We're using a packer-and-sleeve system. We have recently converted the pad drilling, and I'm going to cover some of those pads in a few minutes. But we're doing that as we continue to identify the -- identify the space -- proper spacing for the field. Our 2013 plans are to drill roughly half Codell horizontals and half Niobrara horizontal wells.

This graph has been updated recently and shows the average productivity curve for our horizontal Codell and horizontal Niobrara wells, with the Codell being the green line at the top and the Niobrara being the golden color at the bottom there. You will note that we have completed 40 Niobrara wells and have recently added the eighth Codell well. Both of them has continued to shine with very solid results relative to our 300,000- and 500,000-barrel tight curves that are shown up here. Our costs continue to come in at $4.2 million and our rates of return range between 40% and 140%. We continue to utilize small chokes in the flowback process and that's why the early time is somewhat suppressed relative to our tight curves. We have data that supports this. We make better wells over the long term and that's the reason we do that.

Now I want to go into greater detail on the Codell performance. The green line on this graph is a repeat of the prior slide, showing our average Codell well. The gray lines in the background are the wells individually. And you can see that there isn't one well that is carrying this. It's really a combination of all of those wells.

The other part of this equation that I want to emphasize is that many of these wells are in the outer reaches of the field, and I'll show you a map here in a minute. But in the areas where we have had difficulty making vertical wells from an economic perspective, so not only are we adding to the list of wells what we're drilling, but we're also drilling in areas where it's difficult to get good vertical wells in the past.

I do want to point out the first well. Okay, I'm not there yet. Okay, so we have had many discussions as to why our Codell does perform better than our Niobrara, and we believe it no different than in terms of the vertical well productivity that the Codell is a little easier to frac and it's also a little higher permeability and that's the reason why it performs better than the Niobrara at this point.

I would hope that this provide some insight to all of you as to why we have planned for half of our wells being in the Codell this year. We expect over 30 wells by the end of this year to be online, and I have one final point on that. I have 8 wells in the sample set that are early there. And you can see that it drops down to 4, down to 1. And I believe that the better indicator of the Codell well performance will be shown in a few minutes by Jim Lillo, and he's got a lot of data that's not only ours, but some of our competitors'. So it's a very interesting set of data, and I think that's a better indicator of where we're headed.

This map reflects the 8 Codell wells that we have -- producing. They are located across the field, as you can see, and not isolated to one portion of the field. We do -- we don't have wells down on the southern edge yet, but I'm going to show you a pad where we're going to start drilling down in that direction soon. The data will be very helpful when we start looking at how -- at our booking process at year end, and it also gives us confidence as we drill across the field. And this is where I do want to point out, that well right there is the first well. And as you can see, it's on the very outer reaches of the field and it is a very -- it's been a very good well. So it's critical to recognize the position of that well and the number of those others, which are pretty much on the -- scattered across the field.

This slide shows 3 sections with the development of different horizontal well densities. The left section represents our booking of proved reserves. We have 4 Niobrara wells booked in our proved reserves. The center section shows the booking of our 2P reserves. We have 8 Niobrara and 2 Codell wells in our 2P reserves. And in our 3P reserves, which is in the right section, we have 12 Niobrara and 4 Codell wells. This is -- this ties to our 2,000 locations that we've discussed prior in the presentation. Please note, the legend for the vertical wells is the black dot and the horizontal wells are colored by zone. This methodology carries through the end -- the rest of the presentation.

The next group of slides I'm going to show you is how our current and future downspace test will support the increased well density.

I'm going to start by defining what the inner core, middle core and outer core is just briefly -- and cover that for a minute here. But this is reflective of an updated reserves booking area process. And as noted, they are titled inner, middle and outer core. Our reserves as of 2012 are booked on this system and it has been blessed by Ryder Scott. And I'm going to leave this for Jim Lillo for -- in a few minutes, but because it was on the slide, I wanted to point out that variation. There's no layout below that.

The distance between the Niobrara wells is approximately 800 feet on this map. And you can see that with that space between the wells, that's roughly 100 acres per well. The pad contains a well in the Niobrara A, Niobrara B and Niobrara C benches, as is shown on the side view, with the Codell well being stacked underneath the A bench well. The average of the 3 Niobrara wells and the Codell well is shown on the graph on the left. And you can see that the Niobrara is in the golden color and the Codell is in the green color and they're performing very similarly. These wells are also performing very well, relative to our 300,000- and 500,000-barrel type curve range.

This slide is at the same full well pad on the right, with the performance of the Niobrara A and C bench only wells shown on the graph on the left, and they're shown separately with the C bench in gold and the A bench in green. Both benches in Niobrara performing between our 300,000- and 500,000-barrel type curves, generating excellent rates of return. I do want to stress that we only have one well in each of these zones and thus, you're seeing the first data that we have obtained. We will continue to add to this set as we progress through this year.

Back to the map that we were looking at earlier, the next pad that I want to look at is in blue. Once again, it's the wells' ranch pad over on the eastern side of the map.

Again the map view and side view of the wells are on the right side of the slide. The 4 wells on this pad are on the north half of the section and are drilled east-west, with 3 wells in the Niobrara B bench. The Codell well is stacked under the southern B bench well on the pad. The Wells Ranch 43-34H well is in the south half of the section and is one of our early delineation Niobrara B bench wells.

The graph on the left reflects the average performance of the full well pad in the gold color, relative to the 43-34H well on the south end of the section.

I hope you appreciate the performance of these wells because they tested several different technical challenges that we faced. First of all, these wells were drilled east-west when we typically drill our wells north-south. We also have -- the horizontal wells are drilled among the vertical wells. So we have vertical production that exists and those vertical wells continue to produce. And finally, the spacing is 570 feet apart, approximately, between our horizontal B -- I'm sorry, the horizontal B bench laterals. With these challenges, the wells are performing very near the 500,000-barrel type curve and are as good as the single horizontal well that's in the south half of the section. The 575 feet between wells is approximately 70-acre spacing. So you can see we've shifted down now, a step, and all of this is encouraging for our flexibility in our drilling program, being able to drill the east-west versus north-south, as well as the tighter spacing that we look to achieve in the future.

Jump back to our map again. This is the last producing pad that I'm going to discuss, and it is labeled, once again, in a blue box as the Schaefer pad. And I want to point out at this point that this in the far northeastern portion of the field and of our acreage position.

It is a north-south pad that is performing very well. This is especially true when you look at its location relative to the Wattenberg Field and our acreage position. The 3 B bench wells are shown on the side view, as well as the Codell under the middle B bench well. With nearby vertical wells and its location, it has performed within our type curve range. This is an area where our results from drilling vertical Codell and Niobrara wells were subpar, and horizontal well technology has made this such that it's very economic for us to drill.

A repeat of the same pad we're looking at here. And I want to point out that the curve on the left now is different. The green curve is to oil production and the gold curve is the wet gas production and it's an average of the wells on this pad. As many of you have heard, we are seeing a slower cleanup of the gas curve, and I want to stress gas here, in our pad development when compared to our individual horizontal well development. The gas cleanup is experienced in the first 60 to 100 days of production and occurs in the majority of the wells that we have drilled off the pads.

Two important notes from this, first, we do see the gas peak in approximately 100 days and it does end up comparable to our single well test at that point, and the GOR ends up comparable to the offset wells. Reserves and liquids performance, et cetera, are all calculated off of this later reserves -- or the later GOR, not that early time cleanup. So Jim Lillo is going to cover that a little bit more, but I did want to stress that.

Second, there is little impact to the rate of return because it is limited to the gas side of the -- or the gas portion of the production, and it is also limited to the 60 to 100 days of cleanup. The oil curve performs similar to the tight curves, so we don't have an issue on the oil side at all. PDC's reservoir and operations groups continue to evaluate data that will help us to better understand this and we will use that as we go forward into the future.

At this point, we have covered the 3 producing pads, with solid results across the field. The final pad that I want to discuss is the pad on the southeastern side of the field, which is labeled the Waste Management Pad, and it is currently not producing. So I'm going to talk about it here in a minute.

But before I do that, I want to discuss a couple other -- of the testing analyses that we've done on our horizontal wells. Two methods are -- and they support our down-spacing, two methods are reflected on this slide. The left map reflects 3 horizontal wells, 2 of the 3 were monitored using micro seismic. The calculated half length, based on this -- based on the micro seismic, was approximately 250 feet. If you do the math, this supports that wells can be drilled on 40-acre spacing. The right graph is a reservoir model that takes the early production from our wells and projects the drainage from these wells. The model also indicates that 40-acre drainage is realistic based on our recent wells that we have drilled. I want to stress that these are basic models and the many factors are -- we need to consider many factors when using these models so that -- the ultimate is the test in terms of productivity of the wells. The models here do support down-spacing, and again, the 70-acre spaced Wells Ranch well showed tremendous result. So those 3 things help us to go forward with what I'm now going to talk about, which is the waste management pad.

This is a 2013 drilling project on a full section. The section has no vertical wells on it. It's scheduled to begin drilling a little later this month and there are 16 wells, total, that we have -- that we're planning to drill, 6 of them are Niobrara B bench wells, 4 are Niobrara C bench wells and 6 Codell wells. The A bench is absent in the area or we would have tested it as well. All of these are -- these wells are staggered, not stacked, and because of frac height growth, we believe that this will improve on our results.

We are testing various combinations of B and C benches, as you can see on the side view, relative to the Codell and see how they work best together and this pad. This pad is a significant part of our budget for 2013 and it'll cost roughly $67 million.

I want to summarize by showing the impact that we will have with the work that we are doing. You can see from the information on the slide that we continue to increase our spending in the Wattenberg Field and project 2014 to increase over 2013. We forecast a fourth-rig starting in 2014. 2011 was the last year that we drilled vertical wells. Beginning in 2012, the horizontal well count, as Bart pointed out, continues to grow and as projected through 2014.

Production also continues to grow dramatically, a 20% growth rate. I also want to note that the liquids growth continues to grow substantially during that period as well. Lance is going to cover this more in detail as he gives more along the lines of the -- more along these lines and a corporate forecast.

I want to now switch gears and move to the east, to our southeastern Ohio, Utica play. We have acquired 46,000 acres that are primarily in the liquids-rich window. This provides us with the potential for 200 drilling locations based on 1,000 feet between laterals. In 2012, we spent a little over $100 million, and in 2013, we plan to spend a little under $100 million, with the focus changing from acreage acquisition this year -- last year to drilling wells this year.

Two years ago we decided that the shale indicators were positive for us to enter the Utica Shale. Our exploration team continues to consider it one of the best unconventional opportunities available. During this 2 year period, we finalized our acreage position and have drilled, conducted significant data acquisition and completed 4 wells, 2 of them are horizontal with reported IPs. We are back to drilling today on our Stiers pad and then we plan to move to the southern acreage to test the wells down on the southern part of the field, and the names of those wells are the Garvin and the Neill. We should have pipeline connections to these 2 wells very early after they are completed.

The July 2013 completion date, here, shown for the first Stiers well is probably more near when that well would be turned online dependent upon how we flow it back.

I want to point out that our focus in the Utica play is in the Point Pleasant. It is the bottom third of the Utica and is definitely the most productive perspective portion of the section based on logs and early testing of the rock. This is a target zone for PDC and for our competitors.

The cross section that is shown here is a comparison, moving from the northeast to the south and the play. As you can see from the map, the southern well log is in our southern acreage. The intent here is to show that the rock properties are very similar in the south to those in the north. And as you all know, there is much more data in the north, including IPs on the wells. Resistivity, porosity and TOC are all very similar across these 3 wells. We have 12 feet less Point Pleasant in the southern Palmer well, which is the well that's in our acreage, than we do in the Onega, and the BTU of the gas is similar between the 2 wells. We feel that 100 feet of rock is very adequate for strong economics in this play. Based on this, as well as other information that we continue to gather, PDC is confident in the quality of our southern acreage. We're very excited to begin the drilling of our Garvin horizontal well and it should be spud in May. We will then move to the west, to the Neill location, and I'll show you those locations here in a minute.

We expect first production from the southern acreage in the third quarter of this year.

This slide shows the significant development that has occurred in and around our acreage position. We have drilled and completed 2 horizontal wells, the Onega and Detweiler, with significant test data that is summarized in the boxes on either side of the map. The Onega IPed at 1,800 barrels of oil equivalent per day and the Detweiler at 2,200 barrels of oil equivalent per day, with each well producing over 75% liquids. Our drilling has already begun on the Stiers, as I said earlier, and in fact we have 2 of the wells TDed and are moving to the third one as we speak, in Guernsey County, and we will then move to the south to begin the delineation of our southern position in Washington County. We're planning to drill 11 wells in 2013, with 7 of those wells being in the north and 4 being in the south. And just to point to a couple of these wells here, the Stiers is located right there, Garvin there, and Neill right there.

I will now discuss the plans for our 3-well Stiers pad. The wells are spaced 1,000 feet apart and turning from south to north, and we are planning to drill 5,000-foot laterals. We have shot 2D seismic, that has helped us to better understand that this particular pad has -- is really not very complex in terms of geology. We're looking at different frac designs and flowback methods in our early attempts to optimize the completions. We're also varying our landing point in the Point Pleasant to better understand the variability and the productivity within the zone. Finally, we do plan to use microseismic to help us better understand the frac geometry that we are creating. As you can see, this will provide us significant data as we move through the drilling program and completion process in the future.

As Bart noted earlier, our Detweiler well was recently placed online, to a temporary pipeline solution, but has limited data. And in addition, that data is very valuable as we progress through, and that we've even been trading that with other operators to get more information on the play. So we are continuing to show target economics. At $8.5 million in capital costs, we are expecting between 500,000 and 750,000-barrels of oil equivalent. This generates between a 30% and 80% rate of return. The price of oil is $90 flat and the gas price is $3.50 flat for the life of the project.

We have significant expectations for the Utica in 2013. We have test data on Onega and have recently turned the Detweiler to sales. We have a midstream solution, that George is going to talk about in a few minutes, for the northern acreage and should have a southern solution in place soon. We will begin to understand the productivity of the northern and southern acreage, that will establish the quality of our acreage, and much of this will provide the basis for our initial bookings, which we expect to occur at the end of this year. Finally, we can begin to understand capital allocation for the next 3 to 5 years.

This is a brief glimpse into the future of the Utica. Our capital and production continue to expand through 2014, and particularly, the production is expanding dramatically. This is done while continuing to operate 1 rig and not getting, really, the full benefit of that rig until 2014, based on the completion timing as well as getting pipeline systems in place. Lance will add more to this in his -- to his presentation in a few minutes.

I'm now going to hand this over to Dewey Gerdom, who oversees our PDC operations, for a Marcellus update.

Dewey W. Gerdom

Thanks, Scott. Good afternoon, everybody. I'll give you a brief update of our Marcellus activity, and we'll start with the Slide 49 -- excuse me, Slide 48.

Today, what I want to do is just give you an update on where we are and where we're headed with Marcellus. As you can see by the slide, we have, in our inventory, 32 horizontal Marcellus wells now. 15 of those are operated, that's what we'll talk about today. The remaining 17 wells go into our inventory as a result of the Seneca Upshur acquisition. They are horizontal wells down in the southern part of our acreage, outside our core area, where we have just overrides and well data for those operated by other companies.

As Bart mentioned in his opening, in previous reports you may have seen where we had up to 150,000 net acres, almost all HBP within the Marcellus. That was as a result of the Seneca acquisition in 2011. We did post closing on that, we had the opportunity to go through -- do our due diligence on the acreage and we went ahead and defected, successfully, about 17,000 acres, we've brought back an additional reimbursement of almost $30 million to PDC Mountaineer. And also we have been on a positive effort to consolidate and focus on our core area which I'll discuss in a few minutes, in Harrison, Taylor and in Barbour County. So we've taken a look at some of that broad acreage position, across 22 separate counties. We've been able to monetize certain non-core assets and let some of our leases go. So that accounts for the difference. And now we have a firm acreage position of about 125,000 acres, of which our focus area comprises 70,000 net Marcellus acres. And in that core focus area, based on a 3P report with current strip, we have 357 locations, and those 357 horizontal locations are comprised of about 30,000 of our 70,000 core acreage within that position. Then we also take our non-core acreage and the remaining acreage inside our core area, and we do an acreage-risk scenario and we do our risking down to up to 75% in some cases, which gives us another 243 horizontal locations, for a total of 600 potential horizontal Marcellus locations across our acreage position.

Take a look at, today, just where we are. This is our core acreage position, Harrison County, Taylor County and Barbour County. What you see is, numbers 1 through 5, we did put a rig back up in the air, in January of this year. We are currently on the D’Annunzio pad, which is labeled number 1 on your slide, and we are on our -- about ready to TD our second well on that 4 well pad.

We'll then go to the Goff area, I'll explain why we're heading into the Harrison [indiscernible]. So we're going to focus on those areas, we'll go there next. Then third, we'll go up to what's called the O.E.S. pad, that is up in the northeastern part of Taylor County. It is an area that comprises almost 10,000 net acres in our position within the core area. It is also one that, both internally, our geologists and our engineers, are very intrigued with. Along with all of our outside consultants, they're anxious to see some tests up there, because we have a vertical well, a vertical horizontal well -- or excuse me, a vertical Marcellus well that was our best producer across our delineation program that we completed in 2011.

So we're anxious to get up there. The pipeline system is in place, George will go through that in a little bit. But the pipeline system is now in place to where we can drill, produce and test that area. That could yield us up to an additional 60 horizontal locations inside that core area. We'll come back down and drill an Armstrong/Reynolds pad. It's right on our pipeline. It's on the western part of our split, in our type curve analysis. And every year that we have drilled in what we call our Taylor County curve, it has increased from originally 3 Bcf to 4 Bcf, and now it's tailing around 7 Bcf as far as the type curve, so we're going to get more data points, which will make Mr. Lillo a little happier. And it's also one of the very few areas where we do actually have an expiring lease. So there's a couple of reasons to build that Armstrong pad. And then we'll finish out the year by spudding our Maxwell pad, it's our sixth well pad back down in the Harrison area.

The slide that you see here comprises 3 curves, it's is a 5 Bcf curve, the 7 Bcf curve and the 9 Bcf curve. These curves were then -- we ran the economics based on $3.50 gas price escalating, with the $7 million capital across cost per well. Under those current economics, you can see a 9 Bcf curve will yield right around a 32% rate of return and then a 7 Bcf curve, right around 20%. With gas prices where they are today, one of the encouraging things that we're seeing right now is we're hovering right around $4 gas. So if you ran those economics at a $4 escalation, the 9 Bcf curve is at 42% and your 7 Bcf curve is roughly 27%. And I'll go into this in a little bit, that's still based on $7 million capital cost per well. Our goal this year is to go to $6.5 million, and if we go to $6.5 million, then by the end of 2014, we believe we can get down closer to $6 million. And if you just apply that $4 gas price to a $6.5-million well, you're up about 47% rate of return on a 9 Bcf well and just over 30% on the 7 Bcf curve.

The actual results to date, by area, our Harrison County average over by the Goff wells. And in that area, our averaging, you can see that they're trailing along, above the 9 Bcf curve, and our Taylor County average is really hovering between the 5 and 7, but our recent results have been much closer to 7 Bcf.

So what does this do for our future? You can see where we've come. On the Mboe equivalent, in 2012, we produced just over 1,000 Mboe net to PDC. 2013, we estimate we're going to be at about 1,358. And then by year end 2014, we're estimating 2,250 Mboe net to PDC. I talk in gas most of the time because as you saw, Bart's curves, our area is dry gas. So for those of who you like to ratchet up to 8/8ths and also use gas. From this standpoint, our 8/8ths production net to the entire JV was 12.1 Bcf in 2012. We project we'll produce a total of 16.3 Bcf this year and next year that will move to 27.1 Bcf.

In 2011, we drilled 6 wells. In 2012, we only drilled 3 wells, when gas prices started to go down. The advantage of our acreage position is we're almost all HBP. We're able to just lay the rig down with no consequence to us. And now with gas prices recovering, we're going forward with our program with an approximate 15 wells this year and 17 estimated for 2014.

I will note that if you do look at the capital expense net to PDC in 2013, the $57 million, and in 2014, that jumps to $90 million. Although, we only drilled 2 more wells, that's not a typo, what happens with these multi-pad producers is we're still going to drill 2 more wells but we're actually going to have an incremental 10 additional completions in 2014, which adds for the total, plus we'll have an incremental addition of almost $16 million in pipeline and midstream cost across our acreage position. So those numbers are accurate.

So how do we get from $7 million down to $6.5 million down to $6 million? We're watching the Utica, and Scott and I are talking all the time, it's really an interesting phenomenon to watch, the growth of the Utica and some of the lessons we've learned as an industry in the Marcellus. We've really come a long way in driving our costs down. One of the things that is significant about drilling in West Virginia is there's not really a flat spot in the state. So what we have to do is we really have to minimize the footprint that we put on these locations. So we're finding a way to standardize those footprints, but to minimize what we do with them as far as water impalements, as far as pits, as far as the size of location. So we're driving those down. One of the things that we did we first came into the basin, it was just not that long ago, from a Marcellus standpoint, is we picked our favorite location and then we did a wetlands delineation at the end of the process. The regulations have gotten very challenging throughout our industry and wetlands are a big hot button. So what we have done is -- now we go out and we do our wetlands delineation first, ignore where the location could be and then work our way from there. We're saving a lot of time and money with that effort.

Our drilling solution is driving the cost down, we're already in the middle of those cost improvements. So I'm very proud of our group, the team that's out there and are drilling. We have had some help from the industry on completion. So frac costs are actually down about 50%. So that helps. The thing I want to just emphasize more than anything else is -- what we're seeing now is putting in place what we call a water management strategy. We have been working on this for almost 1 year and we're going to start laying pipe side-by-side with our gathering system for our water management. Instead of hauling water, moving water everywhere, building large impalements in areas that don't really fit well for that. It will help drive down cost. It's a very big investment to put pipe in the ground to move water, but the payout is significant and easy. And as recently as a couple of weeks ago, one of our competitors, Antero, I believe, made a commitment of almost $240 million to their water management program. So the industry is going to be moving that way, to stay away from moving water on trucks, it's very expensive, and we have already started the implementation of that process.

So, in conclusion, I think that even though we are in the dry gas window with the Marcellus, with our cost management and some of the initiatives we have going forward, and with the excellent results that we have seen to date, it's my opinion -- I think it's our opinion, here, that we can drill effectively and economically, driving our cost down, driving the reserves up to where we can achieve anywhere from 30% to 50% rates of return in the Marcellus.

So, thank you for your time, and I'll turn it over to Jim Lillo now.

James A. Lillo

Thanks, Dewey. This slide is our SEC proven reserve summary as prepared by Ryder Scott company as of year end 2012. Our year end 2012 proven reserves, as you can see, increased 14% from 169 million to 193 million barrels equivalent, while our liquid mix increased from 34% to 48%, and our PV10 increased from $1.3 billion to $1.7 billion. All of these increases, I want to point out, were in spite of lower SEC product pricing, including approximately a 30% decrease in SEC natural gas prices and NGL prices.

Pro forma, our Colorado asset divestiture, our year end 2012 reserves still increased by 6%. Divesting of these gas assets lifted our pro forma liquid mix to 52%. As you can see, our proven reserves were dominated by 149 million barrels of oil equivalent in the Wattenberg Field, representing over 80% pro forma.

Referring to our proved undeveloped reserves, 380 horizontal wells in the Niobrara and 53 horizontal wells in the Marcellus, comprise 93% of our 111 million barrels of equivalent of proved undeveloped reserves. In the Wattenberg, the horizontal Niobrara wells represent 80 million barrels equivalent of the 88 million barrels proved undeveloped reserves. And I also want to point out that pro forma, that Colorado asset -- or the Colorado divestiture, our PV10 is the still $1.7 billion.

Now I'm going to walk you through where we came from, to where we got to year end 2012 from the beginning of -- from year end 2011. The table at the right and the graph on the bottom, you can see our starting point of 169 million barrels equivalent. In 2012, we produced 8 million barrels of oil and divested 11 million barrels, primarily from the Permian Basin sale. Our Wattenberg acquisition added 33 million barrels equivalent of proved reserves. The extensions of 88 million barrels are represented by significant additions in the horizontal Niobrara, 59 million barrels in addition of contributions in the Marcellus of 9 million barrels. The downward revisions of 58 million barrels are primarily the result of lower product prices, including impact to tail reserves and the 5-year rule, with over 35 million barrels equivalent in the PUD losses in the Piceance Basin. Overall, the acquisition and additions in Wattenberg more than offset production revisions and subsequent divestitures to provide PDC with pro forma reserve growth in 2012.

This slide shows our 10 years of consistent reserve growth. As the graph shows on the bottom, with the exception of 2009, PDC has experienced year-over-year increases of reserve growth, reaching over 175 million barrels equivalent pro forma the Colorado divestiture. This is a growth rate of approximately 22%. Correspondingly, as shown on the pie charts, our liquid mix has increased from 15% crude oil in 2009 to over 50% total liquids pro forma 2012.

Now I'm going to talk about the horizontal Niobrara performance. As the map shows, we have delineated the core Wattenberg Field into 3 distinct areas: the inner core, the middle core and the outer core. The different core areas contain wells that have similar production profiles, GORs, NGL yields and overall EURs. The inner core, where PDC has approximately 6,000 acres, is home to wells such as Noble Energy's Gemini, Hanscom and Nelson wells, [ph] all of which have EURs of over 0.5 billion barrels. This area also has highest GORs and the lowest NGL yield of the 3 core areas. The middle core, where PDC has the majority of our acreage, approximately 60,000 acres yields the best overall economics of the core Wattenberg. PDC has over 33,000 net acres in the outer core, which has the highest liquid -- the highest liquid mix of the 3 areas. While waiting for midstream solutions, PDC development is focusing on the middle and outer cores.

Here's a little more data how to delineate the reserves by each of these areas. The chart at the right shows 3-phase EUR distributions of approximately 350 wells in our study. The inner core represents 42 wells, has an average EUR of 500,000 barrels. The middle core represents 171 wells, which has an average of over 370,000 barrels, and the outer core represents 138 wells, which has an average of approximately 250,000 barrels of oil. As you can see by the data set, all 3 of these areas have potential for reserves to fall within our 300,000 to 500,000-barrel type curve range and all wells average approximately 340,000 barrels.

This in-depth study provided Ryder Scott with ample data to book proved horizontal Niobrara reserves across PDC's acreage at year end 2012. The table below shows a breakdown of our 382 horizontal Niobrara PUD locations and associated reserves across the 3 core areas. Proven reserves in the middle and outer areas were booked at 4 net wells per section, while the inner core, being gassier, was booked at only 2 net wells per section. Our internal 3P estimates indicate PDC has almost 1,600 locations and over 320 million barrels equivalent in the core horizontal Niobrara, based on current maximum spacing of 12 wells net per section.

While our current reserve estimates are based independently of individual Niobrara benches, we continue to gather data as Scott pointed out and delineate reserve contributions from the A, B and C benches.

This slide demonstrates the production performance of each core area. The graphs on the left showed 2-phase production, crude oil and wet, gas along with the corresponding GORs over a 24-month period. As you can see in each of the areas, the GOR stabilizes after approximately 1 year. The outer core with a high NGL yield of approximately 110 barrels per million has a GOR that stabilizes around 3,600 standard cubic foot per barrel. This yields a total 3-phase liquid mix of roughly 84%.

The middle core, having NGL yield of approximately 80 barrels per million, has a stable GOR of around 9,000 standard cubic foot per barrel, which results in 3-phase liquid mix of approximately 75%. The inner core has an average NGL yield of approximately 60 barrels per million and a stable GOR of 10,000 standard cubic foot per barrel. The total 3-phase liquid mix is roughly 60%.

I want to point out that while the GORs in the inner and the middle core are similar, the gas stream in the middle core is much richer thus yielding a higher overall liquids percentage.

Finally, as Scott mentioned earlier, the industry data that is averaged on these graphs shows a common clean-up period in the gas production as wells are brought online for the first few months.

Now I'm going to talk about the Codell -- the horizontal Codell development. I'd like to focus on the map showing the industry activity across the Wattenberg Field. There are 29 wells on this map. PDC's wells are in the copper color as Scott previously showed, and other industry wells where we had public data are the gray stars. There's a total of 29 wells on the map. Both PDC and other industry players continue to aggressively derisk and delineate the horizontal Codell potential. Currently, we have 8 Codell horizontals producing and 35 more planned to come on in 2013. PDC's producing wells have shown similar -- have sown similar earlier results as the north Niobrara and as Scott showed, seemed to be outperforming to this point.

In terms of total industry performance, the chart below here shows -- demonstrates the average 3-phase EUR of the existing industry wells are approximately 390,000 barrels equivalent and 70% liquid mix. At year end 2012, PDC had limited data for the horizontal Codell and as a result only booked 5 PUDs, representing approximately 1 million barrels. Since then, we have updated our internal studies and, based on a maximum of 4 net wells per section, we estimate PDC to have 455 3P locations with the reserves of approximately 85 million barrels oil equivalent. We will continue to monitor the downspacing pilots across the field to further evaluate the potential of the Codell for future reserve additions.

This slide summarizes the Marcellus reserves as we continue to evaluate the well performance and delineate the Marcellus -- horizontal Marcellus and our focus areas of Taylor and Harrison Counties as demonstrated on the map. Certain areas as Dewey mentioned, such as the Goff wells in Harrison County, continue to show EURs in excess of 8 Bcfe per well with production histories now of over 2 years.

We continue to evaluate our optimal well spacing and use those findings for future pad drilling. Currently, PDC only has 52 locations booked as proven with 23 million barrels equivalent of net reserves to PDC. Now based on SEC prices year end 2012, our internal 3P estimates show the potential for 242 additional locations with net reserves of over 100 million barrels equivalent. These 242 3P locations represent less than half of the total potential drilling locations in inventory.

My last slide now shows PDC significant 3P growth over the last year. Focusing on areas of continuing operations only and excluding any Utica potential, PDC has experienced an 80% increase in proven reserves and a 236% increase in 3P reserves since year end 2011. In Wattenberg, our proven reserves have approximately doubled and our 3P reserves have quadrupled. These large increases are a result of recognizing the horizontal Codell potential and further horizontal downspacing of the Niobrara on both legacy PDC acreage and acreage acquired in the merit Wattenberg transaction.

We will continue to work closely with our operations groups throughout 2013 to further understand the reserve potential of the Utica. PDC continues to work towards justifying our 3P reserves as technically proven, so we realize SEC proven reserve bookings may be limited to 5-year rule.

Now I would like to turn this over to George Courcier to talk about midstream.

George B. Courcier

Thank you, Jim, and good afternoon, everybody. I'm going to give you an overview of our midstream and marketing efforts across our 3 operating areas. As a midstream and marketing group within the company, we have 2 primarily objectives, and one of those is to ensure that we have sufficient midstream infrastructure in place to gather our gas and process our gas, as well as to have agreements in place to make sure we have transportation out of the basins. Our second objective is to ensure that we have agreements and contracts in place that maximizes our netback realizations for our products.

I'm going to talk about our 3 operating areas in the same order that our previous speakers have, starting with Wattenberg and move through the Utica and then finish with the Marcellus. Each of our basins presents unique challenges, but our efforts in all of these basins are focused on achieving those 2 objectives in all of our basins. I'll start with Wattenberg, where our primary objective, our primary efforts are focused on making sure that there's sufficient midstream infrastructure in place to handle the accelerated drilling that we're undergoing now in that basin. And now I'll talk about the Utica, where our primary objective is getting midstream infrastructure in place in a new basin, so that we have takeaway capability for all of our products. And finally, I'll talk about the Marcellus, where our focus is on building our own midstream infrastructure to ensure we stay ahead of our drilling program.

This slide shows a couple of photographs, which the picture in the bottom left is some of our Marcellus pipeline being installed. Again, in Marcellus, we're actually building our own midstream infrastructure. And on the right is our first PDC processing facility, which is the refrigeration skid that Scott mentioned in this discussion, which is in place at our Detweiler pad in the Utica, and we're currently processing gas there, recovering NGLs, selling gas, as well as our condensate off the site.

In Wattenberg, with the development of horizontal Niobrara, it's been a real challenge for our midstream providers to keep ahead of the accelerated drilling program and make sure that they have facilities in place to gather the gas and process all of the NGLs. To that end, our primary midstream service provider, DCP, has embarked on a very aggressive capital program that will see them install new facilities through the year 2015 that will more than double their capacity in the basin.

In 2013, the key projects that we will see impacting us start with a bypass option that they plan to install in May of 2013, which will give them 30 million of incremental capacity in a short timeframe and utilize some of their compression projects before they get their processing plant in place. That is to be started up by May of 2013, followed by their major expansion, which is their installation of the LaSalle plant that Scott talked about earlier. This is a facility that's going to bring an incremental 110 million a day of cryogenic processing capacity into the basin and expanding on up to 160 million a by the end of the year.

In 2014, they have -- they're in the permitting process for yet another plant called the Lucerne plant, and you can see that in the upper part of the map there in brown, Lucerne 2. That's a 230 million a day cryogenic processing expansion. And by 2015, they have yet another plant that they're planning for -- they're looking for deciding on exactly where the site is.

And in summary, by 2015, DCP, who is our primary midstream service provider, will have more than doubled their capacity in the basin. At the same time, they are working on and constructing an NGL pipeline called Front Range, which will take NGLs out of the basin and take it to Mont Belvieu and allow us to access the Mont Belvieu market. Currently, all of our NGLs go to Conway in Kansas. Mont Belvieu is a higher-priced market. And with DCP's ownership in that pipeline, they will more than double their NGL takeaway capacity as well. And that is expected to come online in the first quarter of 2014.

So the -- as far as gas processing, we are seeing tremendous expansion, and we're confident that with these expansions that DCP will be able to stay ahead of the game and that we'll have plenty of takeaway capacity for our products into the next few years.

Oil takeaway options are also expanding. Currently, we sell the majority of our oil to a local refinery, which is located right -- almost within the Wattenberg Field. However, we've added 3 other purchasers to our mix that have different takeaway options, including a combination of trucking, rail and pipeline to ensure that we have other takeaway capability and can access different markets besides just the local market. We've added 2 of those purchasers just within the last 1.5 years.

And I will point out the photograph in the lower right. That is the LaSalle plant. And that photograph was taken about 5 weeks ago, so they made a lot of progress since then. And they still expect this plant to come online by the end of the third quarter of this year.

This slide summarizes our marketing out of the area. I'll start with crude oil where I mentioned we have 4 purchasers. We transport out of the basin with some of our product use a combination of truck, rail and pipeline with a combination of annual contracts and monthly contracts. And consistent with what we've experienced for the last couple of years, we project, and these are 2013 projections, that we will achieve -- receive a 93% of NYMEX price on our netback. I want to point out here also that all of our netbacks are calculated after gathering, processing and POP deductions. So all of our fees are calculated and are factored into these netbacks.

As far as NGLs, our NGL is -- they're all marketed at the tailgate of the plant. And again our NGLs currently go to Conway, Kansas. But with the completion of the Front Range pipeline, we'll also have access to Mont Belvieu for NGL production.

We expect to see about a 33%, as far as per barrel netback price, 33% of NYMEX price for NGL netbacks. Natural gas, again, sold at the tailgate of our processing plants. The majority of it gathered by DCP. The deliveries are to CIG. And some of the gas goes to the local utility, Xcel. And we expect to see -- and this is again consistent with what we've seen for the last few years, an 88% to 90% netback pricing versus NYMEX pricing.

Moving into Utica, this is a new area for us. We're currently involved in discussions to finalize our long-term gathering, processing and fractionation options. We've recently implemented a short-term solution for our wells up in Guernsey County. And you can see on the map the Northern acreage there where we've drilled our 2 wells, the Onega and the Detweiler. The Detweiler is where we put our processing skid or refrigeration skid. We're currently processing gas off the Detweiler and selling NGLs and selling gas into the gather co -- gathering system, and we're selling to Dominion at that point.

Our condensate is being purchased at the wellhead, taken away by truck to the local refinery. We have recently signed our long-term agreement with MarkWest for this area, and they will have their infrastructure in place and start gathering the gas from the wells in this Guernsey County area by the end of the third -- of the second quarter of this year.

We have also identified a short-term solution for our Morgan County and Washington County acreage. Our first 2 pads, which Scott mentioned, the Garvin and the Neill pads, we will be connecting those wells at Dominion East Ohio, and we will be moving our gas under a temporary arrangement in their existing system. And we are in active discussions with midstream providers in determining what our long-term solution will be for that area, and we expect to have that resolved in the next few weeks.

As far as the Utica marketing, we are currently selling our condensate at the wellhead, and that's transferred by truck to a local refinery as I mentioned earlier. We are receiving about 95% -- that again, this is netback with all deductions. We are receiving about 95% of NYMEX pricing per barrel for this condensate.

The NGL and natural gas numbers you see here reflect our long-term agreement with MarkWest. So this is what we expect to see as projected for 2013, starting when MarkWest connects our Guernsey County production at the end of the second quarter. We expect to see a NYMEX -- netback on our NGL production of about 48% of NYMEX. And that's under an ethane-rejection scenario as there is no ethane recovery occurring in 2013.

Our natural gas, we expect to see a netback price of about 83% of NYMEX in 2013. Again, this is reflective of all fees and deductions.

Moving to the Marcellus. As a midstream group, our primary focus here, and we decided about 3 years ago in the Marcellus that we would build our own infrastructure for a number of reasons. And we currently have 18 miles of high-pressure, large-diameter pipe, and all of them -- virtually all of our Marcellus production is moving on this pipe to 2 delivery points. And our existing pipe is represented in the black on this map, and you can see our acreage in yellow on the background. The plans are to build about 5 additional miles of pipe this year, 16-inch, high-pressure pipe up in the Northeast in the Compton [ph]acreage area that Dewey mentioned we will be drilling the O.E.S. pad. And we'll be putting that in this year. We're in construction right now, and that will allow us to help delineate that acreage. That gas will be delivered to momentum, who is our -- who will take our gas up to TETCO. All of our gas from this area will go up one of the 3 delivery points out of the -- off of our system. They all get delivered basically to the same places, which is a TETCO delivery point in Pennsylvania.

We do have plans moving forward, and the red reflects our construction plans that we have for 2013 and 2014. And that's going to be between 12 and 15 miles of pipe, and we'll obviously facilitate our drilling program moving into 2014. And I'll reiterate something that Dewey mentioned earlier that the great majority of our drilling in 2013 is going to be in locations that allow us to take advantage of our current pipe. So we have minimal pipe construction needs for this year. Most of this is going -- construction is going to occur in 2014.

As far as netback pricing, this is a dry gas basin for us, and so we don't have any NGLs or cruder condensate to speak off. So our gas netback in this area is about 89% of NYMEX.

So this is my last slide, and I'm not going to go through each of these bullet points because it basically summarizes what I've already mentioned to you. We're very pleased with the progress we're making. And we have -- we think we've got a good plan going forward for the next couple of years to ensure that we get our products moved out of the basins and get it sold.

So with that, I'll close, and I'll turn the mic over to our CFO, Gysle Shellum, to talk about financials.

Gysle R. Shellum

Thanks, George, and welcome, everyone. I'm going to spend a few minutes here. My comments will be brief. I want to update all of you on the guidance that we gave in our year end call for a couple of events, and I'll bring those to the forefront in just a moment.

Lance is going to talk about 2014 and 2015, so my comments will be focused on our 2013 guidance. Lance will give you some outlooks for '14 and '15. And I also want to mention there are, in the back of your book, some slides in the Appendix that give you more detail on historical data, trends and weighted average -- cost of capital sensitivity. I'm going to give you just a snapshot of our cost of capital trend, too, at the end of my slide deck here.

So some assumptions, what has changed since the first quarter when we guided earlier? First of all, we added some capital. As Bart mentioned to you, $350 million of our $386 million of drilling capital will be dedicated to Wattenberg and Utica horizontal drilling.

Secondly, the sale of the Colorado dry gas assets. The guidance I'll show you has identified those assets that will be shown as discontinued operations beginning in 2013. The numbers are still there in '12 and in '13 to demonstrate the impact that they will be in our regulatory filings. They will be below the line, 1 line item.

The production forecast. If you strip out the dry gas assets, that 2012 looks like 5.5 barrels of oil equivalent, 5.5 million barrels of oil equivalent. We will be moving up to between 7 million and 7.5 million barrels of oil equivalent in 2013. That's a bracket around Bart's number that he showed you, about 7.3 million barrels of oil equivalent.

Pricing. We presented pricing based on the strip of February, using a high/low oil price for a high/low range for gas. The low price was $3, the high price was $4, and these are NYMEX prices before differentials. For oil, it was $85 on the low side and $100 per barrel on the high side. Liquids in both cases were priced at 30% of crude NYMEX. And our production stream, as Bart mentioned, for 2013 will be 54% liquids during the year.

So this shows you comparing -- compares 2012 actual results. And again this ties to our compliance statements. But we have identified discontinued operations revenues and costs here. The production numbers are -- do exclude the dry gas sale. The Piceance and NECO then have been stripped out of this for comparison purposes and identified in single-line items.

Do we increase capital? $78 million from the previous guidance we gave you. That capital is going into Utica and into Wattenberg. We'll continue to keep the rig in Utica for the full year and the new forecast, and where moving the rig delivery in Wattenberg up by a couple of months. So that's where the capital is coming. The additional capital is going, too.

Our gross margins for the year, Bart showed you, the sales margin is going to be about 80% of revenue. That's about a $38 per barrel equivalent margin. Our cash margin, which is sales less production, less general and administrative costs, are about 64% of total sales. And that's about $30 per barrel equivalent margin.

A significant item to mention here is our DD&A is decreasing by about $1 primarily as a result of the sale of the dry gas assets as well.

So just to summarize here, revenue -- there's revenue growth, there's EBITDA growth, there's cash flow growth, cash flow per share. There's a significant job and adjusted net income because of the DD&A difference. Although, with the amount of capital we're spending, that seems to be a disproportionate number to our metrics growth. And that's because, if you recall back on Bart's slide, and again and also on Scott's slide, the back-end weighting of our production, we stay on a relatively low incline through the first 3 quarters of the year, and it really jumps up in the fourth quarter. So this is leading into a pretty good 2014 as we pick up steam towards the end of the year in 2013.

Look at our liquidity and our leverage metrics. Here you see in the blue, the light blue column, second from the left, is PDC stand-alone. And this is just on our revolver. This does not include any of the term debt. I'll get to that in the next slide.

We start the year with about $49 million drawn on our revolver. We anticipate we'll net about $190 million from the sale of the dry gas assets. The bid was $200 million. If you take out fees and expenses, we're estimating $190 million. We'll pay off the revolver with those proceeds and have a significant amount of cash on our balance sheet when we close that transaction here in the second quarter. This, with our cash flow, will sustain our program for 2013. And on the low side, you can see here in the PDC's column, we'll end up at the same borrowing level that we began the year with at about $49 million. And if we hit it on the high side, we'll be about $67 million.

So we'll still have quite a bit of room left on our revolver. We're beginning the year with $450 million on our revolver, drawn by about $50 million. So $400 million in liquidity beginning. If that number didn't change, we'd end the year with about $400 million of liquidity. We expect that our borrowing base will grow significantly during the year with the new reserves we're adding. So a very conservative measure. We'll have $400 million of liquidity ending the year and that will set us up nicely for 2014.

Our leverage metrics. Debt to EBITDAX is a little bit of the high side of our comfort range at 3, close to 3x. That leverage -- that turns around pretty quickly as we go into '14 and through '15. And again, Lance will show you some of those numbers. So we're not uncomfortable with maintaining that for this year, knowing that going into next year, things are going to improve. And debt to capital, debt to book capital is about 50% at the beginning and at the end of the year. Again, that's a little high, but as we ramp this program up in the Wattenberg and Utica begins to start to contribute, then that number too gets to be a little more comfortable for us.

Some metrics to look at for 2013. Pricing, here the wellhead price is before hedges. Very close to what it was last year. And these are per BOE, which is a change for us. We announced earlier that with the sale of these dry gas assets, we would start presenting our metrics in barrels of oil equivalent, so we're all trying to still get used to it as well. The realized price includes our hedge activity. And just to give you a feel for what that does for us, if we end up on a low side of pricing, $3 gas, $85 oil average for the year, we'll have roughly $38 million of realized hedge gains. If we end up on the high side, the $4 gas, $100 oil, we'll have about $4 million of hedge gains. So our hedges are really buffeting the impact -- buffering the impact of price swings for the year.

Cost metrics. You'll notice all the cost metrics are dropping year-to-year. And there you can see the DD&A decrease for the year. This is largely due to -- the other metrics are largely due to the increase in production, the 30-plus percent growth between '12 and '13. And again, the liquidity, the leverage metrics are at the bottom of the page here, assuming again that we only have a $450 million borrowing base at the end of the year.

A look at our debt structure. You've seen this before. The first bar on the left is our bar -- is our revolver. We are $50 million drawn and $450 million ceiling on it. We're currently going through our spring reevaluation of the revolver. Along with that, we have been talking to the banks about repricing the term -- and terms on the deal. We have not negotiate -- we have not changed the pricing on our revolver for about 18 months. The market has moved in our favor. So we will likely be shaving some cost off on the grid, as well as some of the fees. Along with that, we'll expand the revolver to a 5-year term. So that bar will move out to 2018 in the second quarter. And our nearest maturity then will be our convertible preferred, which is the $115 million maturity in May of 2016. The terms of those preferreds are noncallable to us, and they convert at $42.40. So these guys are currently in the money. They -- we've treated this in our internal models, although we don't go out for you as far as 2016. We've treated this as an equity event. However, we have the option -- the issuer has the option to take these out in either cash or stock.

PDCM, I'm going to flip back because I did -- I blew right past PDCM, our joint venture here. PDCM is the column that's second from the right. This is their revolver. We are -- we consolidate this. This is our share of PDCM's revolver. It shows beginning debt of $26 million. That's 50% of what's outstanding in the revolver at the beginning of the year, going up to around $70 million at the end of the year. That revolver is nonrecourse to PDC, but we do consolidate it, and it does show up on our balance sheet every quarter. You'll notice that our metrics don't really change when we consolidate, but the joint venture uses that revolver for its development, and we don't contribute cash to the joint venture, and it doesn't distribute cash to its partners.

Finally -- not finally, but look at our hedge position. This is as of last week. We actually, in the nick of time, got some oil hedges on for 2014 last week. We are -- under the terms of our credit agreement, we're fully hedged for 2013. We're allowed to hedge 80% of total proved for the nearby 24 months. So oil and gas are fully hedged in 2013 at roughly a little over $90 for oil and right at $4 for gas. In 2014, we're in the 70% range on that same limitation at roughly about the same numbers, $90 oil and $4 gas. 2015, we drop down -- our restriction drops down to 80% of PDP, so we're not allowed to hedge as much in 2015 or beyond the 24-month limit. So we're on that limit. We're pretty close to 70% on gas, and we have a long way to go on oil. Our objective is to try to capture a $90 price in oil and a $4 price in gas. It's a challenge to try to get $90 oil for 2015. Gas is a little bit easier. But we'll work on finishing out this 2015 program this year and into next year to protect our cash flow.

Now finally, just a quick look at the trend on our weighted average cost of capital. This is the weighted average for the years '11 and '12, trending down. If you took a snapshot at the year end of 2012 with our debt-to-cap metrics, that weighted average cost of capital would be 9.75% as opposed to 10.7%. So going into '14, we're trending down, and I think this trend will continue as we get larger and grow stronger and generate more cash flow. And then just a quick note, our $500 million of 7.75% preferred that matures in 2022 is trading at 6.4% yield. So the bondholders are very happy right now. More importantly, this instrument is an instrument that we can live with. If you recall, we called our $200 million of 12% high yield when we issued these $500 million notes. And besides the coupon, there was egregious -- there were some terms and restrictions in that indenture that we weren't comfortable with going out and tagging on another issue with, so this kind of cleans all that up. We now have a high yield instrument and an indenture that we'll be happy to add to in the future.

So that concludes my comments. I'll turn it over to Lance to talk about the future.

Lance A. Lauck

Thanks, Gysle. In this last section of our presentation today, we're going to talk really about 3 things. The first thing is talk about how we've taken several successful steps to transition the company to a 50-plus percent liquids mix. We're also going to demonstrate to you how PDC is positioned for long term shareholder value growth, and then we're going to describe that to you as we look at the next 3 years as we forecast forward several key metrics including production and cash flow.

The first thing we'll talk about are the several key accomplishments the company has completed over the last few years that has really brought us to the place where we are today, and we're excited about where we are today. We positioned the company to deliver long term value growth through the inventory of 2,200 liquid-rich horizontal drilling locations. Included in addition to that, 600 locations in the very prolific area of the Marcellus that Dewey talked about, positions the company with an opportunity investment of about $10 billion. Additionally, we've completed 3 strategic transactions that we believe has really fast-forwarded our transition to liquids. We acquired liquid-rich assets in Wattenberg and Utica and currently divest in dry gas assets in Colorado.

The third accomplishment is the growth of our proved reserves, and really more significantly the growth of our 3P reserves, both to about 52% liquids. And that's up from 15% liquids as of year-end 2009 for a 3.5-fold increase.

One of the key things we want to point out with this is that it's not just growth, but it's value-added growth. So if you look at our 2009 PV10 tax value for proved reserves, it was approximately $3 a barrel. Pro forma for the divestiture, we're now at over $9 a barrel. So on a threefold increase in our per unit value of our proved reserves, and that's the mark of the increased transition that we've had towards liquids.

The final accomplishment is that the market has recognized the value that we've been adding through our market cap increasing to about $1.5 billion where it is today. The key theme to take away today is that the company today is positioned for continued long term value-added growth.

I want to just touch on the 3 strategic transactions that we competed as a company over the last couple of years that has accelerated our transaction -- transition to liquids. The first is our acquisition of Merit [ph] assets, as you guys have heard about quite a bit today. It's in the Core Wattenberg for around $300 million. The proved reserve adds from this, around 29 million barrels equivalent, 58% liquids, and so continuing to drive that liquid mix up within our company. It came with about 2,800 barrels a day of net production on a shallow decline from several vertical wells. The key piece of this acquisition though is the 30,000 acres that enabled us to book several horizontal Niobrara and Codell drilling locations within our 3P inventory.

The second acquisition was a leasehold acquisition in the liquid-rich Utica, and I want to really thank our exploration and land teams for the tremendous effort they put forward with this, because we've acquired approximately 46,000 net acres in the gas condensate and crude windows that we estimate to be between 60% and 80% liquids, and confirm that with our first 2 wells, the Onega Commissioners and the Detweiler, that average about 75% liquids with ethane plus extraction. And we got in for $2,000 an acre, which is a good entry price.

The last transaction is the pending sale of our dry gas assets in Colorado representing only 1% liquids within our portfolio. So the $200 million sales price really enables us to accelerate our liquid-rich drilling from this transaction and pro forma of this, worth 52% liquids. I wanted to just touch on a minute on our non-core Colorado asset divestiture. As most of you know, the assets that were included in the sale were our Piceance assets out in Western Colorado and Northeast Colorado. That's located in the northeast area of the state of Colorado. So when you look at that, the key thing that we want to leave you today is the company's willingness to divest assets to focus our portfolio and to fund higher return growth projects. The reserves that are associated with this, as Jim talk about, about 85 Bcf equivalent, all proved, developed, producing reserves as of year end. The anticipated closing date is the second quarter of 2013, and we're on track for that closing. The proceeds from this sale will help us greatly, not only to fund the gap on our 2013 capital budget, but also to accelerate our liquid-rich horizontal programs and reinvesting this $190 million of net proceeds is a real catalyst to jump start the growth of our company.

Entering into 2013, we identified several initiatives that are important to growing the value of our company. Now with the pending divestiture of $200 million and subsequent reinvestment into our liquid-rich horizontal drilling, we are already executing on these first 4 initiatives. On the prior slide, we talked about the fact that we're now able to fully fund our 2013 capital program. But then also, we're executing on the second and third initiatives on this page, and that is our margins and our EV per BOE. This is an area that we've lagged the peers in the past because our margins were significantly impacted by low gas prices and our high weighting to natural gas production. And so with the divestiture and reinvestment into liquid-rich, I'm going to show you a slide here in just a little bit to show how our margins substantially increased, and now we trade at or above the peers in our analysis within this group and within this metric of margins.

The fourth thing I want to talk about is the divestiture enables us to accelerate our 3-year compound annual growth rate in production, all focused on liquids, and we'll show you that slide here as well in just a minute.

The final 2 are areas that we knew that we needed to have a plan of action in place. George talked earlier about the work that we've been doing with DCP Midstream, and the work that they're carrying out to work not only the short term, but long term growth of takeaway from the Wattenberg Field.

And then finally, as Scott touched on, our final initiative was to demonstrate the value of our Southern Utica acreage position and -- where we hold about 75% of our Utica acreage. So after we drill the 3 wells and the Stiers pad, we're moving to the south to drill 2 wells to test the acreage to the south.

Let's talk about 2013 to '15. And the first thing we wanted to do was just to share with you, again, our business strategy because we believe it's clear and focused. Our strategy is create shareholder value through the organic growth of our 3 premier horizontal plays: the Wattenberg, the Utica and the Marcellus. As you can see our objectives are straightforward, and it's what we really believe adds shareholder value for many years to come. And that's to grow our production reserves in a value-added way, which will be demonstrated in the growth of the cash flow. Our strengths are what really enables us to add shareholder value over the long term, and that is we have 15-years plus liquid-rich horizontal drilling inventory. We operate all 3 of our core fields so that we can control cost and the timing of the development, and we're high, high percent HBP.

Finally, I wanted to highlight what we believe are some of the catalysts for our company going forward. We're positioned to accelerate the pace of drilling, which provides additional production and cash flow growth for our company. And as you'll see in just a minute, we plan to accelerate the pace of drilling over the next several years while managing our balance sheet.

Another catalyst I just want to call out is how our company is working to really demonstrate the low-risk, high-return value of our 3P reserves. And this is an important piece to us because we want to provide the market with real visibility for the high-return value and nature of our inventory because that's the future growth and value add for the company. And you've heard a lot of different projects that we're working on, several within the Wattenberg, with the additional -- all the intervals there, as well as Utica North, Utica South, as well as Marcellus. So all these areas, we believe, over the next several quarters will demonstrate the value of our 3P inventory to the market.

The last catalyst is just our focus on continuing to generate improvements in our cash margins because that's what drives value over time.

The next 3 slides, we provide estimated production, cash flow and capital projections from 2013 to 2015. And we do this utilizing our internal planning model, and the purpose of these slides is to provide a snapshot of the depth and the quality of our horizontal drilling inventory and our ability to generate strong cash flow and earnings growth to the future. For the purpose of modeling, we're utilizing the NYMEX strip based on March 1, 2013, and then we just add back the basin-specific netbacks. So on this first slide, our estimated production growth is shown through 2015. For each year, we're providing a range of production using a stacked bar graph to show the low and the high side of our estimates. As we talked about earlier, for 2013, our production growth is estimated to range from 7 million to 7.5 million barrels equivalent. Then we project our 2014 production will increase to a range of 9.5 million to 11 million barrels in 2014. And then finally in 2015, the range is anticipated to be between 12.5 million and 15.5 million barrels equivalent.

So starting with our 2012 production from continuing operations, we're estimating a compound annual growth rate over the next 3 years to range from a low side of 30% per year to a high side of 40% per year. Now this production growth, I want to add, is based on a financially manageable and methodical increase in rig count, over the same period, we estimate that our liquids mix will continue to be approximately 53%.

The next slide presents our estimated cash flow per share outlook range over the 3-year period. As you can see, the strong growth ability of the shares going forward, our cash flow growth is estimated to go from about $6 per share in 2013 to over $9 a share in 2014 and to over $13 per share in 2015. Again, based upon NYMEX prices, March 1, 2013. Now the key driver to our cash flow growth is the growth in our cash margin per BOE, which is projected to be approximately $30 per barrel over the 3-year timeframe. Now this is a substantial increase over the last 3 year's margin, where we averaged only $17 per barrel. Again, impacted by our then high weighting to natural gas and the low gas prices that the market experienced. And for purpose of this margin, we define cash margin per barrel as oil and gas revenue, excluding hedges, minus oil production and G&A cost, all of which you'll find from the income statement.

Now as we grow our market cap, we are increasing our focus on earnings per share. So also provided on this slide is our model estimates of earnings per share over the 3-year period that begins around $1 per share this year to over $4 per share in 2015.

Our final outlook slide is our estimate of capital and debt to EBITDAX over the 3-year period. As we discussed earlier, our capital is modeled this year to increase -- to be about $443 million, and we're projecting that to increase to around $600 million in 2014 and then $700 million range in 2015. The capital provided in the slide includes our net share of capital of PDC and joint venture in the Marcellus that Dewey talked about. This growth in capital is from a growing horizontal drilling pace, which is projected to grow from about 100 horizontal wells drilled in 2013 to over 160 horizontal wells in 2015. Now as we stated earlier, our future growth is tied to maintaining a strong balance sheet and debt metrics, so included in this slide are our estimated debt to EBITDAX over the 3-year timeframe, and these are model estimates as of the end of each year. So as you can see, 2013 year end is projected at 3.2x and is projected to decline to 2.6x in 2015 as our cash flow increases from our high margin horizontal drilling prospects.

Finally, and the key takeaway from this slide, as we project that the company is able to fund our 2013 to '15 capital program from projected cash flow and our revolving credit facility.

This next slide shows the relative leverage that our company has for the high return core Wattenberg horizontal play. As mentioned earlier, PDC is the third-largest leaseholder and producer within the core area of the field behind that of Noble and Anadarko. However, on a per million share basis, our company has the highest leverage to the play. Also included in this slide is a range of rates of return of U.S. onshore basins provided by Crédit Suisse Equity Research last year, and the key takeaway is that our company is positioned in 2 of the top return plays in the U.S. onshore, with 2,200 horizontal wells in inventory, 2,000 of which are in the Core Wattenberg.

And finally, our long-term vision. This slide highlights the long-term vision of the company. It's to grow PDC to a mid-cap E&P company. Our plan to execute this vision includes several key factors. First, we want to accelerate our growth in production, reserves and cash flow, because that's the drivers of value. Secondly, we want to demonstrate the high value and low risk nature of our horizontal inventory to provide the market with clear visibility for that value-added growth for many years to come. We're going to focus on cash margins and earnings per share, and we can do this now because we have over 50% liquids in our inventory and through the reduction of our operating cost on a per-unit basis over time. Finally, our long-term vision seeks to maintain financial strength and flexibility.

And with that, I'll turn the meeting back over to Jim Trimble.

James M. Trimble

Thank you, Lance. I think now we'll go into the Q&A section. So if anyone has a question, please raise your hand, and we'll get a mic to you.

Question-and-Answer Session

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Neal Dingmann with SunTrust. Just a quick question on the type curve that you have or I guess the EUR estimate that you have on the Utica, I forget what slide here, roughly around like Slide 40, I guess it is. Just wondering for Barton, for one of you guys if you could talk a little bit about some of the estimates in that or if you could discuss, I guess, maybe the type curve or something around that? I don't know what you're thinking about for depletion rates and et cetera, but those rates just appeared a little bit low, so I'm just wondering what the estimates are in there.

Barton R. Brookman

Yes. And I think you're talking about some of our peers who have some estimates up over 1 million barrels, Neal.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division


Barton R. Brookman

More on the condensate window, which is probably the biggest driving force. We used the Eagle Ford as an analogy. We've got reservoir modeling we're doing. We've got the early IPs on the wells and some additional flow testing we've done in the Onega well that all incorporate into building those curves. But at the end of the day, the ultimate driver is going to be the long-term production on the wells. So it's the best we can do now with the limited data we have, but we feel pretty good about where we're at on it.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay, and then, on the Utica, would mean now that you've seen, I guess, your first couple of wells, have you changed your thinking as far as, if you look at the build out, I mean, what do you think is the optimal, as far as the lateral length stages? I mean, we've heard, I think, Chesapeake said something on -- few thoughts on their side on Monday, but you and others suggest otherwise. Bart, just wondering if you look at, I guess, basically just the completion technique, which resides for optimal?

Barton R. Brookman

As Scott said, we're still working on where we're landing in the zone. Completion techniques, clearly, I think, are going to see a trend towards more stages per thousand foot, if that makes sense, or shorter stage lengths, possibly some smaller fracs overall per stage, not dramatically smaller, though. So you're going to have more stages, trying to break a lot of rock. We're definitely seeing some technical data in the Utica that is going to support that. Our lateral length right now, the Stiers pad, where'd -- I think we're just over 5,000-foot, our goal for the team is to really push to that 6,000-foot level, our laying groups diligently working on trying to pull acreage together to achieve that. And long term, the goal is to be in that range, will you'll see a 7,000 or 8,000-footer from us over the next couple of years, possibly. But right now, I don't think we have the acreage to pull one of those off, but again, our goal is more in that 6,000-foot range.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay then, just lastly, remind me after the spires. what's the plan? I know you go Washington, was it for 1 well? If you could kind of refresh me, maybe for you or Lance, for the remainder of year, what the plans are?

Barton R. Brookman

Yes, well, as Scott said, we just finished up the second Stiers well in approximately a month we'll TD the third Stiers well. At that time, we'll move the rig to the Garvin, which is on the Eastern portion of our Northern Washington County. We will drill that well, hopefully, beginning in May. Most likely, frac that sometime in June, the whole shake and bake tiering concept is something our team is really diligently looking at. Most likely, we will have some type of a cure period on that. So you'll see that Garvin well come on, I would say, maybe July, August time frame. The rig, after drills, the Garvin will go over to the more westerly side and drill the Neill well, was originally named the Maxwell. We changed the name due to land issues, but -- and so that spud should happen in June. And then sometime in the third quarter, you'll see IPs on that well. The midstream solution on all of the Washington County acreage should be in place when we are ready to bring these wells online.

James M. Trimble

Just wanted to add on that, Bart, when we -- after we drill the second well in Washington we're taking the rig back up to Guernsey.

Unknown Analyst

You guys showed some comparable rock quality for the Southern Utica. Can you talk --

James M. Trimble

Did you identify? I can't --

Unknown Analyst

Yes, I'm sorry, it's Jeff Bernstein from [indiscernible] back here. So you showed some info on the comparable rock quality, but could you talk about the pressure regime, if there's any difference from the kind of overpressured area in Noble?

Barton R. Brookman

Yes, and I can make a comment on the east to west from the Hickenbotham over to our Guernsey. We definitely -- the Hickenbotham well, we saw a tremendous pressure regime, it's in the gassy portion, some of that you expect, we also saw some frac gradients, so we're substantially higher. As far as how you're moving south, I can tell you this, without giving me all the data, we only really have 1 data point, that we're still really doing some testing on, as related to our Palmer well. What we have told the market is, we are expecting above normally pressured on virtually all of our acreage. The only exception would be the very, very, very most western tip of the Morgan County, but virtually all of our acreage, we're expecting better than normally pressured.

Unknown Analyst

Kim [indiscernible] from MLD [ph]. You said you were evaluating the data to better understand the slower cleanup of gas in the Schaefer pad. I was wondering if you perhaps -- I'm over here. I was wondering if you've spoken to your peers about those results and if there are any theories on that at this point.

Barton R. Brookman

The answer to both questions is yes. We've had a lot of good discussions with our peers, particularly some of the guys at Noble. I can say this, I believe the industry, in general, especially in the lower GOR portions of the field, for the downspacing efforts, are seeing a similar cleanup trend, and Scott, jump in here, because I -- we're talking to everybody, and it's very similar. The oil comes on very close to type curve, and you have a 60 to 100 day cleanup of your gas production. It's somewhat counterintuitive technically to what our operating team would expect, so we're still doing a lot of work to try to understand what's going on as far as this gas cleanup effect. We did not see this as dramatically, we saw minor, minor amounts of this on our delineation program last year. So obviously, the amount of frac we're putting down there, the tightness of the laterals to each other, is somehow impeding that overall relative perm of the gas early in the life of the well. What exactly is going on, we've got a lot of theories. I can probably spend an hour on the theories that we have. And you don't want me to talk about PBT analysis that we're working on right now, so.

Unknown Analyst

All right, thank you. And just one more question. Can you just talk about the orientation of the laterals, the East-West versus North-South, and what's controlling the orientation?

Barton R. Brookman

Yes, and a great question. As you saw with the Schaefer, and I think Scott tried to point it out, one thing we learned is that, that East-West orientation probably, given the performance of that Schaefer pad, the orientation may not be as a big a driver as we thought in this play, which gives us a lot of confidence as we continue to work with our acreage configuration, and we have areas where we may have to go East-West more than north-south. If we had a preference in the play, based on the microseismic that we have right now, it would be, to be north-south. But as Scott presented in the data, we're not uncomfortable going with the East-West type orientation.

Brian M. Corales - Howard Weil Incorporated, Research Division

It's Brian Corales from Howard Weil. Just a question on the south plant, does that solve most of your takeaway issues in the near term, say the '13 and '14, or is that something -- still a work in process?

James M. Trimble

Yes, the south plan itself does solve the takeaway issues from the Wattenberg Field, and as we work through the different volume increases from the field, we're working very closely with DCP to help them understand the volumes we have increasing over time. And with that, they've got this staged growth of 2 additional plants that -- as they continue to grow this in increased capacity over Bcf a day, it is staged in that way by DCP to make sure they keep up with the rate of production growth from us and Noble, primarily.

Brian M. Corales - Howard Weil Incorporated, Research Division

And one more, on the CapEx, I guess, '14, '15, you're relatively aggressive. Can you maybe talk about, what your comfort level is when the debt side is 3x on the debt-to-EBITDA, are you all comfortable there, or are there things outside of the capital markets that you can monetize, help supplement? Would you consider bringing in a partner, et cetera?

James M. Trimble

We're comfortable, on a little bit on the comfort side of 3x, we'd like to see it between 2 and 3, the debt-to-EBIDAX. So we can live in that range. There are a lot of things we could do to bring that down, all the way from equity market transactions to bringing in partners. Now we aren't considering any of that today for this year, and I doubt that we would be, unless something will really change, we'd be inclined to bring a partner in on any of this.

Brian M. Corales - Howard Weil Incorporated, Research Division

Is there, I mean, is there other assets, some of the pipelines of sell to your portion of the Marcellus, something of the like that, you'd consider, or?

James M. Trimble

Yes, I'm sorry, we don't have anything in the pipeline right now. With the assets that we're getting ready to sell, it really cleans up everything except for the Marcellus, and we have announced that, we've always looked at Pennsylvania and the Marcellus as something that wasn't core. But if we sell something inside the JV, that fund stay within the JV, so.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Welles from Johnson Rice. 2 real quick ones. One on Page 28, the Riteaway C Bench test. Do you guys have microseismic on that? And if so, how far up into the end of feed did that frac out?

Barton R. Brookman

We do not have Microseismic on that pad. And your question is -- you're asking if we do have Microseismic, how far did it show our growth was in B?

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division


Barton R. Brookman

Okay. So well, as I can -- I know this, we have tremendous site growth on all of those zones. When you frac to C, it goes into the B and possibly into the A and B are the same. We know that from our Microseismic in a lot of past technical data. As far as how high it goes on that particular pad, no, I don't have any microseismic to support that.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

And then one, there are a couple of moving parts on the IRRs and the PV10s on Page 22. I think in your last presentation, the PV10 was 7.5, now it's 5.5 for the top-end range. But the IRR went from 123 to 140. Can you explain those moving parts?

James M. Trimble

Bear with me. Welles, we may have a typo. I'm just here with Lance and looking at a note. We'll have to get back with you on that. I'm not sure what's going on. We may have a typo on this.

Lance A. Lauck

Yes, it shouldn't have materially changed, Welles, from our last presentation on it.

Barton R. Brookman

The reserves haven't changed, the pricing scenario has not changed, the operating cost assumptions have not changed, the IRR is slightly tweaked. I'm not sure what happened to the PV10. We're going to have to get back with you on that one.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Okay. I think Welles asked my question already, but on Page 58, would you mind kind of going back to that? It looks like you got 3 different distinct area? And can you tell me, roughly at which point does your sort of oil/gas ratio stabilized from your experience?

James A. Lillo

Okay, yes, on Page 58, if look at the graphs on the left, those graphs are actually -- plots of wet gas, oil and GOR, and GOR being the gray line. And as you can kind of see, after about approximately 12 months or so, the GOR is relatively flat, it really starts getting pretty stable at the 6-month period, and it stays relatively flat, each of the areas after that.

Irene O. Haas - Wunderlich Securities Inc., Research Division

And how long does it -- it just kind of keep at that ratio for indefinite period of time?

James A. Lillo

Yes, I mean, you could extrapolate that out, yet the way we forecast it is to keep it flat from that point on.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Okay. So can you give me, sort of a roughly average of the inter-core, middle-core and outer-core, sort of percentage of oil, as you kind of hit that stabilized point in time ?

James A. Lillo

Sure, the GOR in the -- well, yes, that should have [indiscernible]. It stabilizes on the outer core of about 3 point -- or 3,600 standard Cp per barrel.

Irene O. Haas - Wunderlich Securities Inc., Research Division

And how much is roughly like, sort of oil/gas mix, do you have a number for that translated into percent?

James A. Lillo

Percent liquids? Yes it was, hold on, here. Total liquids was about, on the outer core...

Barton R. Brookman

I got it, excuse me, I got it. In the outer, it's 84% liquids.

James A. Lillo


Barton R. Brookman

In the middle, it's 75% liquids, and the inner, it's 60% liquids.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Okay, and of that, how much is -- is it all oil?

Barton R. Brookman

For the liquids? No. It's only oil and NGLs, and it's the result of the gas being richer in...

James A. Lillo

In the actual page that Irene is on, is Page 56, where we've got the individual components laid out between the inner, middle and outer core areas. And so, as we look at our GORs over time, and we saw the clean up and increasing and stabilizing out, as we look at that, we include that in with our full EUR life of well projection, with these percent liquids and that's all part of our analysis where we run our economics on.

James M. Trimble

Any other questions?

David E. Beard - Iberia Capital Partners, Research Division

David Beard with Iberia. Just on your projections, on Page 84, for production, would you just care to talk about your assumptions for the growth rate from the Wattenberg, or the range, or something of that, from that field that's embedded in those numbers?

Barton R. Brookman

Yes, so we kick them off a good start in the individual presentations, where we talked about the 2014 volumes, in each one of the individual sections that was covered by Scott, for Wattenberg, and for the Utica, as well as Dewey's section for the Marcellus that ran set up for over time. So that's where we've got those volumes split out from there, specifically. Just to maybe give some more definition on that, for 2014, Wattenberg is 7.3 million barrels. That's kind of a number, that's kind of right in the middle of that range. And then for 2015, the Wattenberg is about 9.5 million barrels. Utica goes from 1.2 million barrels in 2014. That was presented in Scott's section, to around 2 million barrels in 2015. And then the balance of that is from our net share of the Marcellus in West Virginia.

David E. Beard - Iberia Capital Partners, Research Division

Just thought I'd like to -- can you give the liquids growth? And could you follow up on your assumptions in the Utica, your 500,000 to 750,000 barrels EUR type curves, as you roll the production into those forecasts?

Barton R. Brookman

Yes, we're utilizing that type curve range in our projections going forward, for Utica.

David E. Beard - Iberia Capital Partners, Research Division

And lastly, following the sale of the dry gas assets, does that change your revolver capacity?

James M. Trimble

We don't anticipate much of an adjustment at all. We had -- the bank hasn't finalized their look at the spring redetermination, which is going on now. But with the reserves we added, that Jim went through, and then you can figure out how much we've sold, we're in net add in reserves from the last periods, so. And we're net add liquid reserves versus the dry gas we sold. So we don't expect it to move that much at all in the spring determination as a result of the sale.

James M. Trimble

I think there's one other question up, the percent of liquids overtime, too.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Yes, can you just give us the -- it's David Tameron from Wells Fargo. Can you give us the -- your '14 and '15 mix of liquids and gas?

James M. Trimble

Right. Both for '14 and '15, that's 53%. And so that's our percentages overall as we grow over the next couple of years.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And then back to the Codell and Niobrara, you got [indiscernible] to Codell on the -- you have the Niobrara, you guys drew a map on Page 24. Or you had that black outline on Slide 24, is that your interpretation of where the -- what's the meaning of that line?

James M. Trimble

Yes, that's what we're considering the core for the Codell.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Is there an implication that outside that, it doesn't work, or...

James M. Trimble

The implication is, outside that, it gets bent, or is not there.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And along the same lines, there's some debate about whether the -- you frac into the -- and maybe that's the question over here, but do you frac into the Codell when you -- or you frac into the Niobrara when you hit the Codell? Are they communicating? I know you guys indicated, you didn't see a whole lot of communication, but...

James M. Trimble

We've run some tracer work on that, David. The majority of the Codell fracs are contained in the Codell zone. You have good barriers. And as Scott touched on, the frac dynamic is probably one of the reasons you're seeing a flatter curve on the Codell, along with better perm. You're probably breaking a lot more rock and getting better extension. So we think the bulk of the Codell fracs are staying in the Codell.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, and last question. LaSalle Plant, DCP's talked about August, so you said September -- what do you guys plan for in your -- what sculpted your forecast?

James M. Trimble

We modeled -- we're planning on an August, September startup. We -- and I think Scott tried to touch on this. We recognize these type of facilities are not light switches. They just don't come on. They're going to take a month or 2 to get all the bugs worked out. So we modeled October 1st, we have a curtailment factor built into our Wattenberg production for high line pressure. We modeled that going away, partially, in the fourth quarter. So October 1. So we anticipate that plant really contributing to a production bump, beginning October 1. And that's part of the reason you see the Wattenberg jump and our liquids jump in the fourth quarter.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And really, the last question this time. Can you give us a price that can use in your -- Are you in 3 and 90 and 4 and 100 low on high? What numbers are you using for your forecast?

Barton R. Brookman

Okay, Dave. So for the forecast going forward, we used in March 1st strip, and we're adjusting that to the basin-specific areas. So that's all of the 2013, '14, '15 projections for the cash flow are based upon the March 1st strip. I think -- it seems that there are some individual curves that others have presented that use 90 flat, and 350 flat.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Adam Michael of Miller Tabak. I wanted to ask you if, you guys have given any consideration on trying some extended reach laterals. I know Wattenberg, some other operators have seen some encouraging results, taking the laterals out a little longer, mostly in the Niobrara, but possibly in the Codell as well.

Barton R. Brookman

The answer is yes. We actually have a Codell that is a 6,000-footer. I believe we have a handful of not the 9,000 or 8,000s that you've seen, but some additional 6,000-foot laterals on our drilling schedule as we go through this year. So the team is really trying to test that concept. We have some challenges with the overall acreage position of really going out to the 8,000 and 9,000-foot. So that's currently, that 8,000 to 9,000 is not part of our operating plan. One of the other things is, there is a mechanical risk. I heard of a well this week, I think an 8,000 footer, that they could not get the liner down. So for a company like PDC to have a, say, a $6 million, $7 million well in the Wattenberg, where we have a mechanical problem, we've talked to Jim extensively about this, and we're very comfortable with the results. We're getting our 4,000 and 5,000-foot laterals, pushing it to 6,000, but we may not make it a regular practice to go 8,000 and 9,000.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

A question about on where the densities can ultimately go. If I look at data points from some of the other operators in the basin, and the fact that we haven't reached the limit yet, can you comment on what stands in the way, or what the challenges might be for getting to say 10 to 12 C benches, 10 to 12 B benches and 4 to, I don't know, 6 or 8 Codells, ultimately, even though that's obviously not something you've been able to confirm yet?

Barton R. Brookman

Let me take a stab, and Scott, if you want to jump in here on this. The challenges related to that, I think are, primarily reservoir and recovery factors in economics. From an execution standpoint, on our acreage, I think we could achieve -- I think our totals are somewhere near a 30-well per section equivalent. So I do believe there is that -- our 3 yellow acreage plots have all of our inventory, I do believe that the scenario you laid out is an opportunity out there. But I believe it's going to probably take another year, maybe 18 months for us to get the empirical data to really support that. PDC as a company has to be very cautious about overly -- being overaggressive in pursuit of that optimum point. I believe, our 2,000 is up even from 1,400 that we announced just a few months ago. We've gained enough confidence in some of the data we're seeing, and some of the things Jim presented that, that 2,000 is a real number. So this is moving very quick, if we were here a year ago, I think we had 400 or 540 locations in the Niobrara. We're talking about the Codell, and here we are with 2,000. So it's a good question. I can't tell you where it's going to land, though. I do know this, other operators, right now, I know there's a 24 per section test, we've seen a 30, 30 well per section test out there, we haven't seen any results from those. But I think over the next 12 months you're going to see a lot of data.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

And I thought someone else have an indication, sort of counterintuitively, that as they stay denser, they're actually getting better recoveries per well, or is it just way too early to be drawing those conclusions?

Barton R. Brookman

I think it's too early, they may have some early data that indicated that. I think you have to be careful where it's at in the field. I think there may be been some theories that the old zipper frac concept, that the fracs were actually enhancing each other. But we don't have any data in house yet to support that.

James M. Trimble

Any other questions? Okay, well...

Raymond J. Deacon - Brean Capital LLC, Research Division

Actually Jim, can I ask one? It's Ray Deacon from Brean Capital. With the Utica and transportation, I guess, what's your assumption about the cost to move gas? And also, if you could maybe just give a comment on, if you do cut $1 million off of your Marcellus well cost, what do you think that can do to returns?

James M. Trimble

George, do you want to jump on the...?

George B. Courcier

Well, our -- just on, we our assumption on the gas, of course, our netbacks was based on our -- the midstream component was based on our deal we signed with MarkWest. On the sales side, the issue is what the price would be if the gas delivery point of MarkWest is TETCO M2. So we're looking at the sales at that point, current, which is somewhere around Dominion, Dominion Plus 5, something like that. So we haven't made our long term marketing arrangements. We would be marketing, we will be marketing our own gas out of that tailgate, and we haven't concluded that arrangement yet. But basically, we assume somewhere around Dominion, and sales at the tailgate of [ph] the plant at M2 on TETCO.

Raymond J. Deacon - Brean Capital LLC, Research Division

Well what's the MarkWest processing cost?

George B. Courcier

No, we have a confidentiality agreement as far as specifics. I can say that it -- it's acreage commitment, it's fee-based.

James M. Trimble

Dewey, do you want to cover the -- go through those numbers again?

Dewey W. Gerdom

If we go from a $7 million cap down to a $6 million cap, as we answered the previous question, on the 9 Bcf curve, the rate of return is 53%, and on the 7 Bcf curve, it's almost 35%. That's why we're driving the cost down.

James M. Trimble

Okay, well, any other questions? If not, I have to say, I'd like to say thanks to everyone for coming today. I hope you take away how excited we are with the opportunities we have at PDC. And now again, I think I'd like to just recognize Heather and Marty for the good work they did in putting all this on. Thanks again, everyone, for coming.

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