PDC Energy, Inc. (NASDAQ:PDCE) Bank of America Merrill Lynch 2012 Global Energy Conference Transcript November 13, 2012 11:15 AM ET
Lance Lauck - Senior Vice President, Corporate Development
Everybody thanks again for coming. Our last presentation going before the lunch is from PDC Energy. Lance Lauck, is Senior Vice President of the Corporate Development. He will be presenting. PDC Energy again is close to bid under our market cap, has its prime operations in the Rockies and the part of Appalachian.
So, without further ado, I would just ask Lance to take over. Thanks, Lance.
Thanks, [Ravi]. I’d like to thank Bank of America-Merrill Lynch for the opportunity to present PDC story here today. To startup with, I’d like draw your attention to our Safe Harbor statements and as we will be making forward-looking projections today.
For those of you that are new to the PDC name, we are about $1.5 billion enterprise value company. We are headquartered in Denver, Colorado. We trade on the NASDAQ under the ticker symbol, PDCE.
Our company has proved reserves of little over 1.1 trillion cubic feet equivalent and of that about 34% are liquids, about 49% proved developed. The focus for our company is in three key areas presently and all through horizontal drilling.
The first is the DJ Basin which is home to the Wattenberg Field and specifically the core Wattenberg Field for us and Anadarko and Noble, again very good results from our horizontal drilling programs there. Not just in the Niobrara but also in the Codell formations as well.
Then over on the Utica side and Appalachian, we secured 45,000 net acres in the wet-gas and oil windows of the play, and as you probably heard from industry there are significant initial rate coming from various wells in area, from Gulfport, Entero that’s around our acreage position there.
Then also the Marcellus in West Virginia, but we are experiencing EURs in the range of 5 to 7 Bcf per well. Following our 3P reserve is about 2.3 trillion cubic feet equivalent and we’ve got an inventory of about 6000 projects that will drive the reserve growth for many years to come.
One of the key themes of PDC over the last of couple years is the transition our reserve base and portfolio to higher per spent of crude oil and natural gas liquids, and we are executing on that plan and I’ll show you some more data on that in just a bit.
So as you look at PDC and you think about investment in our company, couple of things to really point out here. First off, we got a very stable base of production from our long-lived assets in Colorado and Appalachian, two areas we’ve been operating in for a significant number of years.
And then on top of that our growth is driven by several high return liquid rich projects. The focus being the Wattenberg Field where we currently have two horizontal rigs running there, and based upon the tight curves that we have for the areas, we are experiencing rates of return in the range of 40% to over 120%. Thus far we’ve identified about 546 locations in our inventory but like to point out that we have substantial additional potential through downspacing in the horizontal Codell.
The liquid rich play in the Utica is also key driver for us and we’ll update you here in a just a bit on some of the key activities that are going on in that area what we are seeing there in industry.
A couple of things about our company’s solid balance sheet, we’ve got a large held by production position our acreage so we are not against time hoc to develop our significant acreage position and majority what we have we operate. So we have control on the timing and space.
Then we also very strong in hedging, we believe that its important to have strong hedges in place to protect our cash flow and we’ll show slide on that in just a bit.
The company has experienced a strong track record of growth over the last several years, on the production basis we’ve grown over the last five years about 21% per year and then on the reserve basis we’ve grown about 26% per year over the same period of time.
Couple key themes from this, one is that, we are increasing our percent of liquids in our product and also in our reserves. In our reserves 2011 pro forma we’re about 34% liquid and this compares to an average say 13% to 15% liquids for the time period of 2006 through 2009.
We see growth of our company in the future coming from the low risk development in the Niobrara and in the Codell formations, and also in the emerging Utica Shale play Southeast Ohio.
This is a picture of our inventories and our company, as you can see it’s a strong inventory and we’re very happy to have 6000 projects in inventory, 4000 of which are shaded in that green has been liquid rich in nature.
Now I’m going to call up three areas here within this and I’ll highlight on with the rest of the presentation in our asset areas, and the first one is the Wattenberg Niobrara and the horizontal drilling opportunities we have there.
We talked about having 546 locations there and I’ll show you the basis there in just a minute. But I want to just point out there is substantial upside to that inventory number 546 both at the Codell and also through additional downspacing within the Niobrara.
The other area that liquid rich has provide a good balance our portfolio is the Utica and in the Utica we’ve identified approximately 200 locations horizontally to drill in Southeast Ohio, and we are excited about what this new asset is bring to the company.
The third area just like to highlight is our Marcellus where we have 600 locations in inventory, primarily all within West Virginia, where we built a very solid acreage position with our partner there Lime Rock and we see this is having a lot of upside in addition to the 600 locations as well.
Just a quick snapshot of our reserve summary, first off, proved reserves, 1.1 Tcf. This is pro forma for the sales of our Permian to Concho that occurred in the first quarter of 2012 and also for our acquisition the Merit Energy assets in the Wattenberg Field occurred towards middle of this year.
As you can see the Wattenberg Field represents about 50% -- 55% of overall proved reserves within field and its also liquid rich field that we project to grow quite a bit in the future.
On the 3P side this is a snapshot of the 2.3 Tcf that we’ve identified and you can see both Wattenberg and Appalachian we see growth projections tied to that and its does include all the wells we have in inventory, so there is more even beyond that that’s not included in our 3P reserves.
Let’s talk little bit about production for the first nine months of 2012. We produced 36.6 Bcf equivalents. As you see the Wattenberg Field represents the largest percent of our overall production, little over 50%.
Follow then by our Piceance Basin which is in Western Colorado which is very stable long-lived gas production and follow then by the Appalachian Basin that’s there in West Virginia and Pennsylvania.
If you look at the production by commodity type in the lower left hand side of the page you’ll see Wattenberg about 60% of our overall production and Wattenberg is liquids 40%, crude oil 20%, natural gas liquid.
I’d like to point out that we only drill horizontal wells within the Wattenberg Field. We are targeting the oily areas of the field and we are experiencing about 70% to 80% total liquids as compared to the 60% that represented here from the overall production from the field.
So for the third quarter 2012 commodity mix for the company as a whole running about 33% liquids, 22% crude oil and about 11% natural gas liquids.
We are very focused on lease operating expenses, if you look at third quarter 2012 we had $0.89 per Mcf equivalent. This is a very competitive price and cost for us and we take a lot of focus at our operating teams to make sure that we keep cost low as it improves margins without throughout all of our assets.
$0.89 compares very favorably to the full year 2012 up about $0.91 per Mcf equivalent. And as you see many factors impacting lifting costs and including continued improvements in the water management in the Piceance Field and also through increase production, but a team has done a very good job in managing costs throughout our company.
Let talk the asset areas and the first thing I’d like to share is the core Wattenberg Field and our horizontal Niobrara program there, and PDC is the third largest lease holder and the third largest production within the core of the field, you see the [cross curve] we’ve outlined in the black line on map on the right side of the slide.
In yellow you see PDC’s acreage position which is about 103,000 net acres in the core area of the field and that’s was brought about by the additional 35,000 acres that we picked up from Merit Energy earlier this year to equal then 103,000 acres in the play in the core area.
High percent liquids as we talked about 70%, 80%, we’ll show actual performance here, but the typical type close range from 300,000 to 500,000 barrels equivalent per well, excellent returns, 40% to 120%, and we are just over 1000 potential additional locations in addition to 546 to the downspacing and also to the Codell development.
I think the key takeaway from this slide is that if you look at us and Anadarko and Noble where we drill wells horizontally throughout the whole play area. You can see that we are all achieving a very consistent results across the whole field and its shows the quality of the play inside the core area.
I wanted to show just a quick slide that shows how we stack up with our acreage and the exposure that we have per $1 million of enterprise value. While we are the third largest lease holder [rest] we are the largest company as far as from exposure to the play basis for $1 million of enterprise value. So a lot of the good things are going in the Wattenberg Field that directly impacts our company.
We’ve broken the Wattenberg into three areas that we look at for future development. The first we’ll talk about is a north area where we plan to spud 37 wells this year. With that we’ve got an average peak rate of about 500 barrels and a 30-day about 400 barrels a day.
We are focused in the north area this year, because the high percent of liquid that we see in this area of the play 65% to 85%. We also like to center area and we picked up additional acreage’s here from our Merit Energy acquisition here and you see their liquids go from about 40% to about 70%.
The lighter center as well from higher EURs in the southwest area of that center area, so that’s an area that’s going to be a focus for us in the future but for now we are focus where we get the highest percent oil and that’s in the northern area.
In the south of the Merit as that we had acreage their prior and that’s why picked from Merit Energy and Anadarko and Encana and others are drilling wells in that southern area, and we’ll begin to look delaminate that area for us next year.
The thing we like the most about the DJ basin is the multiple zones that are perspective for horizontal development and you can see the Niobrara B has been sort of the main foundational zone, Chalk Benches that we have drilled in for -- the wells that we’ve drilled primarily thus far.
But in addition to that we are beginning to drill several Codell wells and we’ve spud and plan to spud six wells in the Codell during 2012, and we are getting very good results from the Codell Sandstone as well.
So, when you look through this pay section here, couple of the zones of the Codell of the Niobrara steep, where we plan to test the oil towards the end of this year and participate with an outside operated party on the Niobrara A by some time early next year. But a lot of potential on the playing area, and we are going through a lot of different down spacing within the field area.
This next slide really shows line of sight, growth to our reserves for many, many years to come. We got three scenarios here that we will highlight the first. Thus far we have puds and approved reserves. And as you see on the left-hand side there that we have 165 horizontal wells booked with Ryder Scott, here as of pro forma for the Merit Energy.
So there’s got to be two wells per section. The inventory that we talked about, the 546 locations represents five gross, four net, wells per section and that was represented by the middle part of graph. Then on the far right side, and this is where a lot of the industry is going us and Anadarko and Noble with the resource potential and we are looking in this scenario, a 12 gross wells per section, seven in the Niobrara, five in the Codell.
And with this, our location count increases to well over 1,800 locations or approximately 10 times, what we have booked under proved reserves. We are currently drilling our fifth downspace pad within the Wattenberg Field. We have three pads on line. They are producing the downspace scenario that you see on the resource potential side, and we plan to update the market on that later this year. But we are very encouraged with the results.
And if you look at the kind of the production over time, and we show here how the Niobrara and the Codell have produced relative to our 300 and 500 barrels EUR type curve. And just to call out, I think we are using prices of about $90 oil flat and $350 gas. And we soon returned to work from 40% over 120% return.
The red line that you see, there is the average of our 25 Niobrara wells that’s projecting around that 350,000 barrels EUR per well. Finish a green line and that represents our first Codell well, the Codell Sandstone is just below the Niobrara. As you seen from that, give me a little bit level RP but is really drawing a very, very nice plus decline throughout the first 120 days and trendy more towards the upper end of the range of the EURs.
The second Codell well that we brought online, initially has some facility constraints on it that we’ve been able to resolve and to never open the well up and you can see our heads starting to trend now with the range of $300 to $500 per barrels of EUS.
A very good results, very consistent results and there is a lot of in place resources in the Wattenberg Field in the core area is really the place for seeing. I want to touch on little bit, as far as Wattenberg production by quarter and really specifically about telling the downtime, the curtailment that we’ve had as a result of high line pressures from our midstream provider.
As you see the first quarter, it did well. It’s a little under 80 million cubic feet per day net. But then in the second and third quarter, you can see that we had curtailments due to high line pressures and hot weather we experienced during that time. The top of that bar graph represents our expected production in the top of the gray area of each of those bar graphs was the actual production that we achieved during the time.
So the copper cap on the top if you will represents the volume of gas that was curtailed from our vertical legacy wells. Now the high line pressure that we've experienced that industry has experienced in the area, it’s not impacting the new horizontal well. Clearly, a lot higher pressure, lot higher rates didn’t have any problem getting into the gathering system.
What’s affecting some of the older legacy wells, but we are pleased to talk about is the October result where we’ve seen a nice increase in the volumes that we are actually selling, beginning here in the fourth quarter due to cooler weather, due to some system enhancement that DCP midstream has brought back on their system and so it’s also bringing on some of the pad location from horizontal drilling.
This next slide essentially mirrors a lot of the prior slide, which goes total capacity throughput, the midstream provider for the same four quarters. And you can see it for the first, second, third quarters -- a lot of the trends there was they go the trend that we saw on our wells specifically to.
But then you see fourth quarter year-to-date, you can see the production up around 430, 435 million cubic feet per day. So we are seeing very good results going into the fourth quarter and with the cooler weather, and that’s where we begin to burn fuel gas in order to keep up lot of facilities in the area. We are thankful and glad to see the improvements in that system.
On a longer-term, DCP has a plan to nearly double the capacity of their system to take it from around 430 million a day to about 800 million a day by 2014, and this is going to be primarily carried out by two key plants site construction project. One is LaSalle, which is scheduled for sort of mid to fall of 2013, along with another expansion of plant and at the end of the year of that plant.
With 2013, we should be around the 600 million a day capacity, which is going be great step change in a takeaway capacity from the field. And it will work well to provide the solution for us and noble as we are the primary producers on DCP system.
Then they have further plans for expansion in 2014 of 213 to 230 million a day from LaSalle. But we are working very closely and there is a slide that that they have a multi-year plan to address the issues with the high line pressure, and they are working very hard and they are very much aligned with the operators in order to improve the takeaway capacity.
We will certainly about the Utica field. We are very excited about our position in the Utica play. We are an early entrant here and we are able to mass 45,000 net acres in the play. We have a high-working interest of 95%. And as we talk about earlier, we’ve identified about 200 wells locations to drill horizontally within our acreage position.
Now, as much of quite read, there has been significant initial rates announced with significant mix of liquid from a number of operators in the field, both Gulf Coast and Ventura have achieved significant results within the play area in the acreage that’s on trend is we have there in our Northern area of Harrison County and Northern Noble County.
We are very excited about the rates. It is exceeding our expectation and it’s clearing covering of page for de risking. For us in 2012, we spend $95 million to $65 million of May was the secure acreage, $30 million was to drill wells. And with that we drilled two horizontal wells.
The first two horizontal wells, feel like a commissioners a number 1425 and the Detweiler number 42. Those two wells we drilled – we frac the first well and then make a commissioners and it’s been shuttering for its risk period and we look for first test on it to come about there towards the end of this month and will flow test and gain the result of from that. The plan to frack the Detweiler well in the middle of the September and then we’ll shut it in for two a month rest period.
And then first production from the field is project in the second quarter of 2013, so we are looking and working forward but not by market agreements in place by year end 2012 to have all that going by the second quarter this year, but very good results from industry around this. We very much like the position that we are in and we look forward the results I giving our wealth customers online.
I will talk last about the Appalachian Basin. In these years, this is our legacy position plus we acquired assets from seneca upshur. Here we have 150,000 acres in the Marcellus, 143,000 of the vast majority of it is in the West Virginia side. As far as the activity out there, we have completed a three well pad and we anticipate hooking it up over the next couple of weeks and getting it on line.
We are also looking for picking up a rig in the first quarter of 2013 to drill in some of the very best economic areas of the Harrison County. The capital for that will be funded through the joint venture and not come from the parent PDC Energy. This is a picture of our Tricounty of Harrison, Taylor and Barbour. And then these three areas, we have identified over 350 of the 600 locations that we have in inventory.
So, great and the ability to drill very efficiently from pad location. I want to share results here, page 22 for the Marcellus. You can see that five to seven BTF type curve. In Taylor County, which is the green line as we normalized to 5,000 foot laterals for wells we drilled and that’s why we our development plan going forward.
We are experiencing about 60 CF EURs and if you look at Harrison County, where the North of the 7 Bcf, probably be 8 Mcf range. So here in West Virginia and Northern -- West more Central West Virginia were achieving very good results from the Marcellus program.
Our capital budget for 2012 is $288 million. The vast majority of this is going towards liquids rich project in Wattenberg and in the Utica formation. About 63% of capital fund is development projects, the balance of those as I talked about earlier. It’s about $60 million that went to leasehold purchases and the Utica formation in Southeast, Ohio. But strong capital program, we are putting on our money to work in drilling and development our key liquid rich fields and areas, and it is focused on these types of opportunities.
The company’s, from a financial standpoint, has goal and plans always maintained a low leverage and strong balance sheet. You see pro forma for third quarter. We got a debt cap coverage of about 43% with the debt-to-adjusted EBITDA will be 2.8. From liquidity standpoint, we’ve got just a little under $400 million over the third quarter and liquidity. And we’ve got a revolver of about $450 million and as much as you may now, we recently went to and secured $500 million a bond wit the 7.75% interest rate due in 2022. PDC is a strong hedger with -- based upon putting the lot of volumes into hedge program.
For 2012, we are showing approximately 70%, 75% of our production was hedged for this year. If you see for 2013, on the oil side, we got about 2.3 million barrels hedged between $90 and $100 a barrel. Then also we’re building positions in 2014. We want to be a company that start ahead couple of years that has hedges in place in order to protect our cash flow.
On the natural gas side, we’ve got about 28 Bcf hedge for 2013 and see the full price say around 438 in Mcf. And we’ve built hedges on about half that volume for 2014 or around 14 Bcf for that year.
In summary here, the key investment highlights for company, 6,000 projects in inventory, 4,000 on liquid rich. The core of Wattenberg is a wonderful feel, horizontal Niobrara development. It’s strong. There is a lot of growth in that, growth in our inventory and growth in cash flows and future production, also in Utica Shale and Southeast Ohio where we’re testing our first well towards the end of this month.
Our allocating capital were high, liquids-mix in production and proved reserve projects. We’ve got a lot of operational flexibility and we really got a substantial inventory that can drive multiple years of organic production growth for the company.
We’ll also focus on improving cash margins and we’re doing that. It feels like Piceance where we’ve improved our marketing arrangements there and we’re cutting cost by water disposal.
Our teams have a lot of experience in our core operating areas. And that helps us in several ways going forward that drives value and keeps the cost low. And we also have a product of hedging strategy to protect this in our cash flow.
So, that concludes the prepared remarks and like to turn it over now for Q&A.
(Inaudible) Just to start the Q&A, I was looking at the slide that you have in the Appalachian basically Harrison and Taylor county. So it’s already like what’s going on, if it’s something in between the two permissions, you have and the two counties you have the way we can develop differently because Taylor origins kind of lagging versus what you have in Harrison? I know there are lot of enterprises (inaudible). They have been completed differently. How do we think going forward?
Yeah. Good question. Harrison county, while our experience is about 8 Bcf per well versus the Taylor county about 6 Bcf per well. I think the primary difference is just -- what we’re seeing is, where we’ve drilled so far in Harrison county. It just has improved rough qualities. As far as the thickness of the reservoir and the properties and the Permian Valleys, we’ve got better rock properties and where we’ve drilled so far in Harrison county. And that’s why it’s been primary reason that contributed to the higher EURs.
And as far the drilling plan themselves, the lateral inch will be about the same, about 5,000 feet and the frac designs are fairly similar as well. But the primary reason is just in there as we drilled the spot on Harrison, it will have a little better rock property.
The vast majority of all of our Appalachia lease hold is held by production and we’ve got also the rights to all shallow Devonian and that’s the interval by which is holding by deep production.
Just to go on your natural gas, I think NECO is still in the official list. I think you guys are talking about that last year?
Add some comment to it.
Yeah. Good question, so the status of or NECO asset which is shallow biogenic natural gas in Northeast Colorado as one that we’ve taken also divestiture lift. We initiated that last year but we saw ourselves selling to a market at declining gas prices and as a result, we didn’t feel that we’re going to get value for the upside that we see, kind of, play area so. We just started to repaying that asset and that we’ll have any current plans to market it at this time.
Just an operational question, our use in gas frac, the propane fracking technology in the Niobrara and if you are, is that working well for you?
Yeah. We’ve tried and executed on one of our wells, the gas frac technology and we’re currently studying and analyzing that both for the cost side of it and recovery and comparing that to our conventional fracs that we do in the area and we have not made an assessment yet on the uplift to that. But we plan to do that market making part of our analysis here.
Could you just briefly comment like may be the directional new area, bringing 2013 traffic, up or down or is still some percentage range would helpful?
Sure. While we haven’t finalized our 2013 budget plans yet, we are planning the capital budget of approximately $300 million plus or minus. We’re going to execute the program that we believe would be very impactful to our company because I’ll continue to drill the two rigs in our Wattenberg field as we continue to develop the Codell’s, the horizontal and continue to downspace Niobrara and Codell. And we’ll also start the year with the rig and Utica where’ve identified approximately five relative plant to drill there.
Including to the south, where we’ve drilled in north Washington county, it began to de-risk the area that are towards the south for us as well. So that $300 million in cost that we see going forward 2013 and we are also planning to pick up rig potentially in the Marcellus but as we said earlier, those costs will be carried within joint venture itself and so not an equity infusion by ITC parent.
Talking about the costs this quarter, some more color on making the house services costs us bear witness in gross margin within Appalachian, within Permian mostly where they were last year?
Yeah. So our capital cost, it will start first, our loan value has been very stable. We’ve got long-term relationships with our drilling company and with Haliburton that we continue. We’re don’t have any long-term contracts but we’ve got great relationships with them. So we’ve been able to continue to keep costs similar on the $4.2 million range drilling complete horizontal well. And that’s one of key reasons, the economics are so strong within the Wattenberg play.
First of, [TDs] is only about 7,300 per day then you are drilling complete horizontal wells for $4.3 million to 3,000 to 5,000 barrels of UR. The costs are stable there. In the Utica area, the costs are fairly stable there. Our average cost of drilling completed Utica well is around $9 million and there is additional work and testing that we’re doing that resulted in $9 million per well.
But we think our teams are capable over the next year or so of reducing that costs, under $7.5 million as we do less upfront test work and we bring some of the improvements in things that in technology that we’ve done in Wattenberg to the Utica play.
Overall in the Marcellus side, it’s about $6.5 million per well. The cost there is also fairly stable. I think the pullback on some of the gas prices has enabled there to be substantial services available for us to get out and to drill and complete and frac our wells there.
Another question about Wattenberg area, and then I have a replay? Where do you see yourselves expanding outside of the core Wattenberg area to the north and east Colorado mineral built that is another area that you will grow entry but it seems like there are some very good results along that trend.
Well, we’ve been focused primarily just in the core end of the field and it’s really because of the consistency of the result. It’s got higher cost fee, higher firm and it’s got much more consistency as far as their position of oil across the core area of the play.
As you get outside the play, the results haven’t been as consistent based upon our analysis. And so as you look at the 1,800 plus wells in inventory that we have and that decade plus of drilling that we have. We think we have substantial room to run just on our existing acreage position.
On growth well, about at this juncture is that we worked hard to build a big portfolio and now we want to do is pick that portfolio and turn it into cash flow and production growth.
There is time for just one question. Let me run it up, just sort of get your perspective in macro point. Where do you think oil is heading 2013 WTI and at what price, you would change your behavior in terms of getting back?
So our long-term view of oil prices ranges between $85 and say $95 maybe as high as $100 per barrel. That’s long term but periods of time you’re above that and below that but we’re seeing that things that over time, the market tends to bring it back within sort of that end of $15 per barrel type of range.
As you look at the Wattenberg play itself, I mean this field is very economic and it can continue to develop good returns of prices below $85 per barrel and it’s sort of got very strong economic with 40, 120 plus rate of return, it will go down quite a bit because economic to drill.
So I don’t know that it would change our plans with our reasonable reductions, say below $85 per barrel price. But then on the Utica side, where we sit with that is there is so many liquids that are coming from that as far as the common shale pay as there is so much of our acreage in our common shale play and you see all the results there, several wells over 1,000 barrels a day of just common site. Natural gas liquids of $500,000 to $1,000 barrels a day along with gas that we feel that is going to be very economic play if oil prices return lower there as well.
And keep in mind until lot of 2013 for us and Utica is de-risking and developing our acreage position. So we are going to be learning a lot there. And we’re going to have a bit capital program, just $15 million plan so far that we think what the fields we’re in, the Wattenberg and Utica. They have strong economics and the reason why we moved into these fields in a big way is because we feel that these fields will have economic circumstance in lower pricing environment and then enable our companies to continue to grow even if the prices were pulled back for long.
Thank you very much Lance.
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