Oct 31, 2013
Executives
James M. Trimble - Chief Executive Officer, President and Director Gysle R.
Shellum - Chief Financial Officer Barton R. Brookman - Chief Operating Officer and Executive Vice President Lance A.
Lauck - Senior Vice President of Corporate Development
Analysts
Irene O. Haas - Wunderlich Securities Inc., Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Ipsit Mohanty - Canaccord Genuity, Research Division Welles W.
Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division David Snow Brian M.
Corales - Howard Weil Incorporated, Research Division Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division Joseph D.
Allman - JP Morgan Chase & Co, Research Division Joel K. Havard - Hilliard Lyons, Research Division David E.
Beard - Iberia Capital Partners, Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Jason Smith - BofA Merrill Lynch, Research Division Michael S.
Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Operator
Greetings and welcome to the PDC Energy 2013 Third Quarter Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.
On the call today is Mr. James Trimble our Chief Executive Officer, President of PDC Energy.
Joining Mr. Trimble on the call today is Mr.
Barton Brookman, Executive Vice President and Chief Operating Officer; Mr. Gysle Shellum, Chief Financial Officer and Mr.
Lance Lauck, Senior Vice President, Corporate Development. It is now my pleasure to introduce your host for today, Mr.
James Trimble. Mr.
Trimble, you may begin.
James M. Trimble
Thank you. And good morning.
And thanks, everyone for joining us today to discuss PDC's third quarter 2013 results. As the moderator mentioned, on the call with me today is Gysle Shellum, our CFO, Bart Brookman, the COO.
Also present is Lance Lauck, Senior Vice President, Corporate Development. For your information, our slide presentation is posted on our website for today's call.
And let me begin by drawing your attention to our Safe Harbor language as it relates to our forward-looking statements and projection in today's presentation. I will give a general highlight of the quarter, followed by additional details from Gysle on the financials, followed by Bart on the operations.
We had a very solid third quarter for 2013, with production levels slightly below quarter guidance due to the timing of our Utica and Marcellus startups, along with minor production loss due to the 1000-year flood in Colorado, which Bart will address in more detail. Our production in the quarter averaged 18,600 Boe per day, which was up 29% compared to the third quarter of 2012, with our crude oil volumes up by 40% over the same period.
The year-over-year growth was driven primarily by the continued success of our Wattenberg horizontal drilling program. We also grew our Marcellus production year-over-year and we're beginning to see Utica production in our numbers.
Company-wide, our liquid mix from operations was 50% in the third quarter. The Wattenberg field continues to be the source of the vast majority of our liquids, over 97%.
Production increase from the Wattenberg and Utica wells in the fourth quarter is expected to push our liquid percentage higher in the fourth quarter as well. The financial impact of the liquid mix is at our cash margins, which is sales less G&A and production costs from our operations is approximately $27.5 per Boe in the third quarter.
This is slightly down from the second quarter of 2013, but is nearly double the full year of 2012, which averaged $16 per Boe. We had a net loss for the third quarter of $16 million or $0.46 per share, which includes $22 million in future unrealized hedging losses and an impairment of $2.3 million after tax on our expected sale of our shallow Devonian assets.
Adjusted cash flow from operations increased 7% from the third quarter 2012 to $37 million. While it increased 19% to $135.5 million for the 9 months ending September 30, 2013, compared to the same period in 2012.
During the first 9 months, net cash from operating activities was $119 million or $3.58 per diluted share. In the Wattenberg field, we finished drilling and completing all 16 wells of our horizontal down-spacing project, the Waste Management, which kicked off back in May with 2 rigs.
We have the first 4 wells on-line at the end of September, and 4 more in early October. We expect the remaining 8 wells will be on-line next week.
The early production has been outperforming our established type curves. 4 of the 8 wells are Codell and 4 are Niobrara.
The early production data supports our 16 wells per section in our 3P numbers on more than 2000 locations on our 98,000 net acres in the Wattenberg field. In the Utica Shale play in Southeast Ohio, we're drilling our 10th well this year, which is our 12th total horizontal well in the play.
In early October, we began producing our first horizontal well in Washington County, the Garvin 1H that was drilled, frac-ed and rested during the third quarter. We began production on a 12/64 choke and slowly open it up over the next 8 days to a 20/64 choke when it produced 1530 Boe per day with 54% liquids.
This is an exciting data point for us as it is the southernmost horizontal production in the wet gas condensate window. Bart will provide a lot more detail on this shortly.
As scheduled, the rig has moved back to our southern Utica acreage to drill 2 additional wells on the Garvin pad. We expect these wells will be completed, rested, and to sales by early 2014.
We also added acreage to our leasehold over the quarter, bringing our total now to approximately 48,000 net acres. We also completed an equity offering in August, with proceeds of approximately $276 million.
We used the proceeds to pay down our $450 million revolver to the balance of 0 and had $298 million of cash on hand at September 30. We expect to close the sale of our 3500 shallow gas wells in West Virginia which are held in the PDCM joint venture in the fourth quarter.
We expect to see natural gas volumes from our Marcellus 2013 drilling activity increasing in the fourth quarter, as we have the D'Annunzio and golf pads on-line, and we completed all about 3 quarters of our 81 frac stages on the 3 OES wells. We're drilling the final of the 4 well Armstrong well pad and we'll be completing in November.
At present, we have 5 horizontal rigs drilling. 3 on the Wattenberg and the Niobrara and Codell play, 1 in the Utica and 1 in the Marcellus.
We anticipate bringing in the fourth rig into the Wattenberg field in late November, early December. And as we look to next year, we're anticipating adding a fifth rig In the Wattenberg, possibly around the end of the second quarter and look at adding a second rig in the Utica around the second half of the year next year.
In summary, PDC had a very solid 9 months with strong results from our Wattenberg operations. As forecasted, we expect production to grow from all 3 basins in the fourth quarter of the year.
We continue to focus on adding value for our shareholders and are in excellent position, which our hedge portfolio and substantial liquidity to continue to execute our 2013 and our 2014 capital programs and business plan. Before I pass this on to Gysle for his financial review, I did want to mention that while PDC and its employees suffered mostly minor impacts in the recent floods, the extensive damage from the flood that hit the front range of Colorado caused severe destruction in communities near our operations.
PDC and its employees reached out directly and through relief organizations such as the American Red Cross to help those in need. I appreciate the efforts of all our field employees and our operating teams in not only responding to our business needs during and after the floods, but also in helping the community deal with this disaster.
I will now turn the call over to Gysle for his financial review of the third quarter.
Gysle R. Shellum
Thanks, Jim. And thanks, everybody for joining us today.
As in the past, I'll go through some high-level comments and for a more complete analysis of our quarterly and year-to-date results, please refer to our press release and our 10-Q to be filed this morning. As Jim mentioned, we're a little below our expectations for the third quarter.
Several seemingly minor issues, combined to impact production during the quarter and Bart will elaborate on that in a little bit. Financial results were pretty close to what we expected, if you exclude the small impairment in the quarter.
Oil and NGL pricing improved this quarter over last quarter. That's the second quarter this year, which helped.
So we're still comfortably within our range of our financial guidance for the year. So let's look at some key financial results.
Total sales from continuing operations were $82.1 million on Slide 6 and reflects the 29% increase in production that Jim talked about. Wellhead prices for all products improved over the third quarter of 2012.
Oil averaged $98.11 per barrel compared to $85.45 last year. Gas prices at the well had improved to $3.13 per Mcf in the current quarter compared to $2.54 last year, a 23% increase.
NGL pricing improved to $27.70 per barrel, compared to $24.76 last quarter. Overall, for the quarter, our rated average wellhead price increased to $47.91 per Boe, a 21% improvement from the third quarter 2012.
Year-to-date sales from continuing operations increased 40% to $239 million from $171 million in 2012. Production cost from continuing operations for the current quarter were $19.1 million or $11.12 per barrel of oil equivalent, as compared to $15.8 million or $11.97 per barrel of oil equivalent in the third quarter 2012.
The decrease in the per unit cost between quarters reflects the increase in production. Total production costs in the current quarter increased from the second quarter this year due to more workover maintenance activity and to a lesser extent, some cost related to floods impacting the Wattenberg field.
Bart also has a slide on this that he'll show you in a little bit. Gross margin from continuing operations was $63 million or $36.80 per Boe in the current quarter compared to $36.5 million or about $27.64 in the third quarter 2012.
That's a 33% increase over Q3 last year, the result of increasing oil & gas liquids production. Adjusted cash flow and adjusted EBITDA include net realized hedging losses of $1.5 million before taxes in the third quarter this year, compared to a realized net gain of $13.1 million in the third quarter 2012.
These metrics are non-GAAP measures that we reconcile to GAAP in the appendix at this presentation and also in the press release we filed this morning. This is the first quarter in over 7 years that we've had a net realized loss on hedges.
Most of our oil is hedged in the mid to low $90 range, so we gave some money back on oil and the realized gains on natural gas hedges weren't enough to fully offset the losses. We don't look at that as a bad thing.
We'll take losses on $90 oil all day long as long as prices hold up as well as they have. Adjusted cash flows and adjusted EBITDA continue to increase over the last year even though prior year results include discontinued operations related to the dry gas assets that we sold in the second quarter this year.
The same goes for year-to-date comparisons. Adjusted EBITDA also includes book gains on sale of assets.
This just highlights our ability to grow cash flow and EBITDA while we're selling assets to focus on our liquids-rich basins. The increase in cash flow over last year that Jim referred to is even more pronounced when you adjust for discontinued operations and asset sales that are nonrecurring events.
Adjusted EBITDA per share through the 3 months and the 9 months ended September 30, 2013 was $1.38 and $4.86 respectively before property sales and results from discontinued operations. That compares to $1.16 and $3.87, similarly adjusted through the same periods in 2012.
Adjusted cash flow per share for the 3 months and 9 months ended September 30, 2013, adjusted on the same basis, was $1.09 and $4.04 respectively in the current quarter compared to $0.94 and $3.82 in the same periods last year. Moving down the chart, most of the increase we're seeing in DD&A is attributable to increased production.
This is the first quarter that we recorded DD&A from Utica production. However, the impact from Utica DD&A was pretty small in the grand scheme of things.
The GAAP numbers on the top half of the Slide -- on Page 7 include unrealized gains and losses from mark-to-market hedge positions as well as results from discontinued operations. We recorded, after tax net unrealized hedge losses of about $13.7 million in the third quarter 2013 compared to after-tax net realized hedge losses in the third quarter 2012, with about $27.8 million.
Adjusted net income and loss numbers on the bottom half of the page trips out unrealized hedge amounts, but includes both nonrecurring gains and losses on property sales as well as impairments on properties sold and held for sale. Current quarter includes an after-tax impairment of about $2.3 million that Jim mentioned, related to the proposed sale of properties in the Marcellus joint venture.
The current quarter was right at break even before impairment charges. Year-to-date 2013 includes impairments related to disposed properties and held for-sale properties of about $30 million after-tax.
Year-to-date 2012 includes an after-tax gain of about $15 million related to the sales of properties. So 2013 year-to-date adjusted net income, before nonrecurring events, is approximately $15 million or $0.49 per share.
Year-to-date 2012 would reflect the loss of approximately $6.2 million or about $0.23 per share before nonrecurring book gain on sale of properties. Slide 8 shows our debt maturity and liquidity.
We are undrawn on our revolver as of September 30, and had $298 million cash on hand as Jim mentioned as a result of our equity offering in August, getting us total liquidity of $730 million. We've added a bar on the graph representing our pro rata share of joint venture of over debt even though it doesn't factor into our liquidity.
We include it because it shows a better picture of our consolidated debt. We show our convertible debt at face value maturing in 2016.
However, these notes became convertible to common stock this quarter after our stock traded above the trigger price for conversion for the last 20 -- for 20 of the last 30 days in the quarter. Consequently, the book balance of 140 -- $105 million is shown as a current liability on our financial statements this quarter.
This test will be performed each quarter in the future and the debt will be classified accordingly. No holders have requested to convert to stock at steady conversion price of $42.40 at this time.
We have the option to settle any conversions with cash or stock or a combination of the 2. It's our intention to settle in cash in the event there's a request to convert.
The last light looks at our hedge positions as of October 15. Since last quarter, we added several positions in 2015 and beyond and covering both oil and gas production.
We hedged oil between $87 a barrel and $90 a barrel in 2015 and gas had prices beginning at $4 and moving up. We aggressively worked on locking and remaining 2015 production and we're working on adding hedges for 2016 and beyond., As you know, we aggressively hedge our production to protect our cash flow and capital programs.
That's all I have. And with that, I'll turn it over to Bart for comment on the operations for the quarter.
Barton R. Brookman
Thank you, Gysle. And hello, everyone.
Operationally, a very strong quarter for the company. I have several key updates to provide today.
But let me begin with an overview. Production came in at 18,634 barrels of oil equivalent per day, a 29% increase from the third quarter of 2012.
Wattenberg production continues to improve, up 27% from the same quarter in 2012. Wattenberg now accounts for 78% of the company's production and our drilling programs in this basin continued to deliver exceptional results.
Our Utica production, as Jim noted, missed expectations slightly, this is primarily due to the ongoing midstream constraints, particularly in the Guernsey County area and pipeline delays on our Stiers 3-well pad. We are confident that we are closing the gap on the production as we go through the fourth quarter.
And then our Marcellus Appalachia production, you can see it grew to 28%, we're very pleased with the overall performance of our drilling and completions in this basin. To cover some production highlights for the quarter.
Overall production came in just under our expectations. But year-to-date, we are aligned overall with guidance.
And as the fourth quarter is shaping up, we expect production for the year to be right in line with our annual guidance. Our liquid mix, as Jim called out, was 50% natural gas and 50% liquids.
A little gas here than prior quarters primarily due to the Marcellus production ramping up during the third quarter. And our Codell wells right now are exhibiting a slightly higher GOR than we anticipated.
Let me give some basin highlights. In Wattenberg, 8 of the 16 Waste Management wells are online for our Codell, for our Niobrara, I'll cover this in more detail in a moment.
The flood impact as Jim called out. Early in the flood stages, we had 214 vertical wells shut in.
Currently, we have about 125 that remain shut in while we are repairing roads and tank batteries. Overall for the quarter, the impact was about 10,000 barrels of oil equivalent, total production loss due to the flood.
Very important, the O'Connor plant, which was previously referred to as the LaSalle plant did start on October 9. And I'll give you an overview on that in a moment and show how it's impacting our overall production and line pressures.
In Appalachia, in our mountain air division, we have 3-well pad on the golf base in Harrison County come online in late August and we're currently completing the OES pad, which is a 3-well project in Taylor County. And then the Utica, our Garvin 1H well and Washington County was brought online October 10th.
The Stiers 3-well pad in Guernsey County came online August 21 should note, this was into a temporary midstream solution while we wait for Mark West to finish their pipelines, which we expect to happen sometime in early November. Currently, we are completing Commisioner's 2H well and then Neal 1H well in Washington County established production 2 days ago.
Jump to the one word when we give a quick update on the midstream situation. First, we have referred, again, we have referred to the LaSalle Plant the last 1.5 years and this project was recently renamed the O'Connor plant.
It is the same plant, same location, still operated by DCP. This plant went through startup phase beginning October 9.
Over the last 3 weeks, we have seen total gathering in processing system throughputs improving. Line pressures are coming down.
The company's legacy production is responding nicely. And current estimates show our older wells have improved production levels by approximately 12%.
Expect additional plant capacities to come online by year-end, with total basin capacity with DCP to be around 600 million a day, gathering and processing. The line chart that we display here shows system throughput increasing after October 9th.
You can see with the brown line here, that line pressures have been dropping from approximately 210 PSI, average build pressure to somewhere around 160 PSI. What does this mean for our Wattenberg?
expect strong production rebound in the fourth quarter, expect the legacy production to benefit in 2014 from these midstream expansions, and these expansions will also help accommodate our growing capital programs. Let me jump over to the Waste Management downspace project in the Wattenberg field.
First, as a quick review, please refer to the upper right schematic, 16 horizontal wells in 1 section, 6 Codells as represented by the blue lines, 10 Niobraras represented by the red lines, 6 of the Niobraras will be B bench tests and 4 of the Niobraras will be C bench tests. Though pad locations for the 16 wells are represented on the south portion of the schematic.
The 2 most westerly 4-well pads are currently online and producing at very encouraging rates. The 1 most easterly 8-well pad will be online, as Jim noted in early November.
Let me cover the performance of the first 8 wells. First, as represented in the lower left decline plot, the first 4 Codell wells cleaned up very nicely and are performing just above our 345,000 Boe type curve that we presented on our last conference call.
We're very encouraged that all 4 well Codell wells are producing at very consistent rates. And you can see the excellent economics being delivered here and our well cost continue to be $4.2 million per well.
Next, please refer to the lower right decline curve. Both the Niobrara C and Niobrara B, on average, are performing between our outer type curve and our middle type curve and our middle type curve of 265,000 to 365,000 barrels of oil equivalent respectively.
We couldn't be more pleased with the early performance of this Waste Management project. We view this as an early step towards fully defining optimum spacing in the basin, but this provides very, very strong technical support for our current inventory of 2,000 horizontal wells in this basin.
Let me jump over to the Utica. First, an outline of this map, the wells that we have drilled to date are highlighted in brown and wells remaining to be drilled in 2013 are highlighted in blue and blue.
Currently, we are drilling our 12th horizontal well in the play. We're very excited overall with the results we are achieving both in the northern acreage and now in Washington County.
Midstream is in place for both our fourth quarter production ramp-up and our 2014 development plans. 9 wells will be in full production by year-end 2013.
Our Stiers pad. A 3-well pad in southern Guernsey county is producing into a very limited capacity pipeline right now.
But based on an early rates and pressure data from these wells, they're exhibiting characteristics of the best wells to date for the company in Guernsey County. These 3 Stiers wells have been producing on a 12/64 choke from first day of production.
And then our Garvin well in Washington County. This is the first horizontal project to produce in this county, and we are seeing very strong early production and pressure data.
On this next slide, let me give more specifics on the Garvin well. We're very pleased with the early test data, both production and pressures.
And overview of the drilling and completion here. This is a 4800-foot lateral.
We conducted 22 frac stages. During the drilling, we are very pleased with the overall levels of hydrocarbon fills and pressure indications from the wellbore based on mud weights.
All indications are the reservoir is well over pressured. The pressure and production data support very strong conductivity and permeability in the reservoir in this area.
Let me review the test data. On October 10, the operating team opened the well on a 12/64 choke straight to sales.
Produced the wells for 4 days on this choke level. During this time, we experienced increasing casing pressures.
Over the next 4 days, we opened the choke in increments of 2/64 per day ending on day 8 on a 20/64 choke, during that time, we experienced less than 150 pounds total drawdown on our casing. While almost 4-fold in the production from the well.
We ended on a 20/64 choke at 1530 bills of oil equivalent per day. That is 3 phase and very, very strong tubing and casing pressures.
I should note that we are in the liquid window and our engineering and operating teams have very strong recommendations not to pull these new completions too aggressively. This is to protect the recently hydraulically frac-ed wellbore and also managed the pressure in the liquid-rich windows in the Utica.
The bar chart shows the production and pressure data we obtain in gray, and in brown our calculated risk based in the inflow performance from the well. As you can see, if we were to open this well to a 36/64 choke, the calculated rates would approach 4000 barrels equivalent per day.
Again, we are in the liquid-rich portion of this play. And PDC, as an operator, will not aggressively be opening wells on larger chokes in an effort to optimize a long-term reserve from our wells.
We update everyone on the drilling activity. For the first 9 months, the company's bought 67 drilling projects, all of those horizontal.
47 In Wattenberg, 9 in Utica and 11 in the Marcellus. All of our drilling I would characterize as going very smoothly, and our cost structure is right in line with guidance.
On a non-operated basis through the first 3 quarters, we have participated in 27 projects so far. So far in total, we have either drilled or participated in 94 drilling projects through the first 3 quarters.
For the year, we had 130 gross wells we plan to either operate or participate in. And we feel we are right on target for that number for the year.
We did have 48 re-fracs in Wattenberg we've backed off on based on the timing and startup of the O'Connor plan, currently as Jim noted, 3 rigs running in Wattenberg, we will be deploying a fourth rig approximately December 1 of this year, we have 1 horizontal rig in the Utica running, and 1 horizontal rig in the Marcellus running. Quick update on the company's capital expenditures through 9 months, total capital outlays are approximately $245 million, $173 million of that is in Wattenberg on our drilling and completion activity, $58 million in the Utica, and $13 million on leasehold and some miscellaneous expenditures.
In the fourth quarter, the company should spend approximately $142 million, bringing the yearly total in line with our guidance -- our annual guidance of $387 million. Lease operating expenses, as Gysle said, up for the quarter, as you can see from the bar graph, but expect improvement in the fourth quarter, as we believe these numbers are going to migrate back towards $5 per Boe.
Reasons for the third quarter exceeding our guidance on lifting cost. First, the flood expenses incurred and accrued for.
The flood hit mid-September. This is a fairly significant operating event for our team in Wattenberg.
Over time, we anticipate $3 million to $5 million total will have to be spent, both capital and LOE to bring these properties back up to our operating standards. We also had increased compression, particularly in Wattenberg field as we waited for the O'Connor plant to start up.
And last, we have experienced some permanent increase in our Wattenberg field staff wages. These increases in compensation were required to do increasing wage trends across the entire Wattenberg field.
The good news is, as you can see, from the right bar graph, margins held close to the first 2 quarters at $36.79 per Boe as our pricing slightly improved. So our operational highlights.
Wattenberg, quarterly production of 14,600 barrels of oil equivalent per day, 6,400 of that coming from the horizontal program, 45% of the basin's production is now from our horizontal wells. Year-to-date, we've drilled 26 horizontal Niobraras, and 26 horizontal Codells.
We now have 90 producing horizontal wells in the basin. Our drilling programs, both Codell and Niobrara, are delivering stellar results.
Our costs remain at $4.2 million. We're seeing lower line pressures, and our early downspace test on the Waste Management project are delivering very encouraging results.
The Utica, as Jim noted, we've added 2,000 additional acres, over 48,000 net. Most of the acreage is in a liquid-rich window and enhancing the economics.
9 wells are expected to be online by year-end. Given the limited choke size on the Stiers pad, we're very encouraged by the production in pressure data and we're very pleased with the data from the Garvin 1H in Washington County.
The Neal 1H in Washington County came online 2 days ago. And our current drilling and completion cost in this basin are in the $8.5 million to $9 million per well range.
In the Marcellus, we've had a series of strong pad turn ons here in the last couple of months and the OES pad in Taylor County is expected to have first sales in mid November. And our current cost structure in this basin is $6.5 million per well.
With that, I'm going to put this back to the operator for Q&A.
Operator
[Operator Instructions] Our first question comes from the line of Irene Haas of Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Maybe a little color on the Neal well and how soon would we hear about this particular well? I mean certainly, the Garvin's looking quite good, especially considering that choke size?
James M. Trimble
Yes, as I've said, the new well kind of established first production 2 days ago, or call it a flow back mode right now. Just a summary of that well.
It's a 6,000 foot lateral. We conducted 33 stages of completion on it.
We will probably -- we'll announce our capital budget and production guidance mid-December after our board approves the budget in early December. And Irene, I would anticipate we'll give an update on the Neal at that time in the press release.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Great, how about the 2 Garvin wells. Are they the same configuration as your first one?
Barton R. Brookman
Yes, they're right at 5,000 foot, maybe a little bit more big on my recollection.
Operator
Our next question comes from the line of Ryan Oatman of SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
For this Southern Utica, there's been some talk of natural fracturing down there, did you see that at all? And if so, did it impact your results in any way?
Barton R. Brookman
As I noted Ryan, on my comments, I would say yes. And the drilling process, some permeability tests that we had and definitely the drilling shows, I would say, we have enhanced permeability and enhanced conductivity in this area.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay. And how does that impact sort of the pressure readings in what you're seeing currently and what you forecast those pressures doing?
James M. Trimble
Oh boy. I think hopefully I'm answering your question.
We are very encouraged by our pressure gradient we're calculating, I'm not going throw to our current calculations out because we're still gaining data, but as I noted, we're well over pressured here. As I, noted we've got good conductivity, great shows during drilling, and we've got great, great permeability, relative to even in the Northern acreage on this early testing that we're going through.
Hopefully, I'm answering your question.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
No, no, that's good. I guess, take a step back, speak more broadly here.
Very early days, but how would you compare this Southern acreage or at least what you're seeing on this first pad with your other Utica and Marcellus that you got in the Appalachian Basin?
Barton R. Brookman
Oh boy, and that's a tough one Ryan. I mean, obviously, we're a little more gassy, we were at 54% liquids, the first 2 that whether are more in the high to mid 70s, and as we go through the liquid window on this, the production management, the pressure management is going to be different, and if you go Eastwards, dry gas, this play -- people will manage the production even -- more different over there.
So to compare and contrast, we could probably spend an hour on that, I can tell you this, we did see enhanced permeability based on some DFIT tests in the Southern acreage, we did see what we think is enhanced conductivity. And we are over pressure between both areas.
Operator
Our next question comes from the line of Ipsit Mohanty of Canaccord.
Ipsit Mohanty - Canaccord Genuity, Research Division
My questions on Wattenberg, you drilled your Waste Management section was in the outer curve, but seems like the well results have come, between the middle and the outer, Codell has come better than type curve. So given that the results are coming closer to the middle or it is better than outer, do we expect the decision of your type curve on each of the middle and outer curves?
Barton R. Brookman
So are you asking -- no, I would not say we are there yet, Ipsit. I think if you look at the location of the Waste Management, it's in the outer area, but it's fairly close to the middle.
So I think if our engineering team were in here, they'd say, they're pleased and this is performing right in line with where they had hoped when we planned the project in the Niobrara and I would say, we are probably in the Codell -- on the Codell side, we are very, very pleased, it is probably outperforming our expectations slightly.
Ipsit Mohanty - Canaccord Genuity, Research Division
Okay, well, my follow-up is on that then, you talked about Codell doing better than you expect, yet you've probably hinted at a slightly higher GOR could you elaborate on that these?
Barton R. Brookman
Yes. In this is probably tied back currently our Codell program, we're seeing slightly better GORs than we had in our budget.
And in some of our engineering, this is a directly related, I think, to the relative perm of the rock, it's still really crappy perm relative to old conventional plays. But it's better permeability than the Niobrara, so we're probably seeing the gas flow through the rock a little easier, definitely early time and that is resulted in just a little bit higher GOR in the Codell.
Operator
Our next question comes from the line of Welles Fitzpatrick of Johnson Rice.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
Obviously, with the Stiers flowing into the low-pressure line, you can't really look at that [ph] piecework, but you did see any difference between the 30-day and the 60-day rested wells relative to each other? That might shift your methodology as far as how long you want to rest them?
Barton R. Brookman
Yes. We have enough data that we're gathering that I think our operating team here is leaning towards shortening the rest period.
We haven't finalized that recommendation. But probably, more importantly, Welles is, some surfactants that we use that we are very encouraged by, that we think are enhancing performance on the Stiers pad.
So we've got those 2 things that we think, along with longer laterals and more stages in a variety of things. And as I noted, these wells are flowing on a 12/64.
We think the 5th of November, MarkWest is going to be ready. That will give us a lot more flexibility to open these wells up.
We won't pull them real aggressive, as I noted. But overall, we're really pleased here and the rest period we think is probably going to shorten if anything.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
Okay, perfect. And then on Slide 16 that you guys talked about, is that kind of a theoretical outline or are you guys continuing to march up that choke size and then the implication will be that, that 30-day rate, if you release, it would be north of the 15?
Barton R. Brookman
No. We're not marching it up above 20.
And as I noted in the liquid window right now, we're not pulling these new completions beyond that level. And as I noted, some of that is the recently frac-ed wells.
We don't want to do that. And some of it is when you're moving toward a retrograde or liquids-rich window, you really -- it's key to not pull the well and drown the well with liquids.
So there's a variety of reservoir, lot of theory behind that, but we're going to hold on those choke sizes when we're in the liquid-rich portion of this play.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
Okay, perfect, and just one last one, the 2,000 Utica that you'll added, is that in the south?
Barton R. Brookman
I'm sorry...
James M. Trimble
It's primarily in the southern acreage wells.
Operator
Our next question comes from the line of Leo Mariani of RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Just following up on Utica acreage, I think you guys made some comments that you've got an appetite to the -- add more acreage, is that going to be largely in and around Washington County, and is there any type of acreage shortage you might have in terms of what you think you can kind of get to there?
Barton R. Brookman
Just real quick, as we said, we budgeted $17 million this year to add acreage. And we've picked up 2,000, we continued to work in and around our existing acreage plays, whether it's in Washington County or Guernsey .
So we're just continuing to fill in the holes. And we continued to work on that.
So obviously, we want to keep adding over the next few years. A lot of it is driven by price.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
That's helpful color for sure, just thinking about the Utica, and you guys said that you really didn't have much production on the third quarter and there's been some infrastructure issues, can you kind of talk us through how that can ramp in 4Q and expect to have a lot of infrastructure kind of issues behind you, when you'll say, is there a time frame there is to like early next year, how should we kind of think about production ramp?
Barton R. Brookman
Yes, first key component that is MarkWest Seneca plant I believe this week is up and running. It's going to give them some flexibility, I believe on their overall midstream reliability.
Our original Onega and Detweiler wells, we think are going to have much more reliable deliveries in midstream, providing as we go through the fourth quarter. So that's the first component of the fourth quarter.
The Stiers pad, as we noted, is really limited right now. We'll have a little bit more flexibility there starting November 5th.
The Garvin well just came online and is adding to the fourth quarter production at very, very strong levels. The Neill well is on hopefully will really be kicking in production here over the next week.
And then we have the Detweiler wells, 2 of them that are scheduled, I believe, for a late November turn on. MarkWest will be ready for those.
They'll make a nice bump in December. And then, am I at 9 yet guys?
I'm pretty close, Leo. Again, we'll have 9 wells total by year end online.
So all those, we think are going to be layer in as we go through the quarter. And as I said, really helping ramp up production.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
And do you expect those 9 wells to generally be able to slow on constraint at that point?
Barton R. Brookman
Yes, yes. We definitely in the South and the North, absolutely.
David Snow
That's helpful. And I guess, in terms of the flood in Colorado, do you guys have any sort of ballpark estimate for how 4Q may be affected in terms of volumes loss?
Barton R. Brookman
It's going to be relatively minor, Leo. We have the 125 wells still shut in.
They are old legacy wells. I don't have that number off the top of my head, but I wouldn't anticipate, it's going to be a big number.
We don't think it's going to knock us off our fourth quarter guidance.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Got you. Okay, and in terms of Appalachian, you guys talked about an asset sale, I know it's something that you guys have discussed for a while, it sounds like maybe it's kind of more definitive in terms of exactly what you're selling in timeline, can you give some more color there?
Barton R. Brookman
We've announced that we have 3,500 wells that are old legacy, shallow Devonian producers. It's not a lot of volume and we've been working with -- we've signed -- hopefully I think we're getting ready to sign a PSA, we hopefully get things closed, just it's all the paperwork that's required, we said we getting closed in the fourth quarter.
It should be done by the end of November, 1st of December.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Got you, that's helpful. And I guess in terms of the Niobrara Waste Management pad, do you guys think there is going to be any interference between the B and the C zones?
How are you guys thinking about that?
Barton R. Brookman
It's probably too early. Based on the early data that we have in the early production data, Leo, we're not seeing production interference.
But give us a little more time on that. And I can promise you this, by Analyst Day, which is early April, we're going to have a full detailed review of the all the downspace product and the opportunities for the company based on the Waste Management pad.
Operator
Our next question comes from the line of Brian Corales of Howard Weil.
Brian M. Corales - Howard Weil Incorporated, Research Division
And maybe a follow-up to Leo's question, with early success at the Waste Management, are you all going to try to downspace further, maybe at some of your peers are doing in and around your acreage?
Barton R. Brookman
Yes, 2014, you guys can expect the 16 wells per section type spacing to be the bulk of our plan. And we will also be piloting and testing some that are in the 20, maybe slightly greater than that equivalent.
And the bulk of that expansion will be higher density in the Niobrara section. So yes, we will take this to the next level, as we go through the next 12 months.
The operating teams are currently working on those plans. As Jim noted, we will have 4 rigs here by the end of the year and a fifth rig sometime in the first half of next year.
So we are going to have a lot of drilling and operational flexibility to continue to pilot downspacing.
Brian M. Corales - Howard Weil Incorporated, Research Division
And then switching to the Utica. You mentioned bringing the second rig in I mean, how do you foresee, is it going to be 1 rig in the north, 1 rig in the south, how do you foresee that, those rigs setup?
Barton R. Brookman
Yes, conceptually 1 rig in the north, 1 rig in the south based on the Garvin data, and pending the Neill data you'll see a slight overshift to the Southern acreage, which is logical since we've got 75% of our acreage in the south. So if anything, you can expect with the second rig maybe slightly more proportional capital dedication to the Southern acreage.
But expect good activity in both areas.
Brian M. Corales - Howard Weil Incorporated, Research Division
Okay. And then 1 final question, it sounds like you're kind of changing your thoughts on the resting period, is there a standard lateral or is that based on the lease [indiscernible] , What is the thought there between lateral and frac stages?
Barton R. Brookman
Okay in the frac stages, I have really migrated to stage per 200 foot, plus or minus, -- yes the acreage configuration absolutely is dictating all operators lateral length. But our goal, and part of what Jim was referring to with bolt-on acreage in the areas that we currently have acreage position.
Our goal is to strive for 5,000 to 6,000-foot laterals in this play. And part of that is what we are doing with the acreage grabs.
We call them bolt ons. Trying to give us the ability of longer laterals.
Operator
Our next question comes from the line of Jack Aydin with KeyBanc.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
Most of my questions have been answered. Looking at the Garvin well, the 4,800 lateral, that was because of the acreage limit or by design?
And if you normalize it, you did 6,000 feet lateral, what kind of outlook would you have seen in terms of data?
Barton R. Brookman
And Jack, probably not a perfect correlation, but since this is a fairly -- we're at 54% liquids, it's a little bit gassier. It's proportionally going to increase your performance through the lateral length.
Definitely on some of the gas plays, you're seeing that correlation much tighter versus more oily plays in the country.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
Okay. You have almost 75% of your acreage in this area, Neill, Garvin area.
Now with the Garvin and Neill, what you think -- what percentage of that acreage you might be thinking is dearest when you have the announcement with Neill?
Barton R. Brookman
So with the Neill or with just the Garvin?
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
Let us take Garvin and then Neill.
Barton R. Brookman
The Garvin probably de-risked 15,000 of our acres. The Neill will de-risk another, I'm going to say 10,000.
And Jack, those are really, really rough numbers off the top of my head.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
That's fine. I'll take them.
Now on the Stiers pad, you have 30 day well resting period and 45 and 60. At first, you're using -- how much uplift in cost you will experience by using the surfactant on the 30-day resting period?
Or does it make a difference?
Barton R. Brookman
I can't reveal that. I can tell you there is a cost impact as far as the exact amount that something I can't reveal.
On the 30 and 60-day, I think we've have covered, in fact, we actually did not have a 45 day. We had, as it turns out, operationally, we had a 30-day and 2 60-day.
And as I noted, some of the technical data we're gathering is leaning us towards shortening that 60-day rest period.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
How about the uplift in terms of production just initial data that you seen in 30 days and 60 days? What [indiscernible]
Barton R. Brookman
It's too early for me to give that.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
Okay. And final question on DD&A, your DD&A, $29.60, could you -- that's a lot substantially higher than last year and also higher than the second quarter, could you go through the component what made that cost go to that level?
Gysle R. Shellum
Jack, this is Gysle. The initial DD&A on the Utica well was at a higher rate from -- Utica area was at a higher rate than Wattenberg and Marcellus.
I think that rate is probably going to settle down a little bit once we get a better feel for what the -- what the curve is going to look like. I don't have detail on DD&A for each basin handy.
But I will say that a lot of that increase is due to production. If you look at the MD&A and the 10-Q, I don't have in front of me, I'll give you a little more detail out of that.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
Would you book some of the -- would you by year-end, you'll be able to book some reserve from the Utica, if you do, what kind of trend we might be looking at DD&A going forward?
Barton R. Brookman
The first part of the question, yes. We'll be booking PDP and most likely modest level of PUDs Jack, in the Utica based on their early data we're gathering and some pure data.
As far as what the trends in DD&A.
Gysle R. Shellum
We don't know what the reserve look like, we won't know what the rates are going to look like.
Operator
Our next question comes from the line of Joseph Allman of JPMorgan.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Brook, on that Garvin well, since you're not opening the choke, should we assume that, that production decline or the production ratio be fairly flat here because that well is effectively constrained?
Barton R. Brookman
I think that is a fair assumption, Joe. When you look at the type curves that we've published, relative to some of the practices.
And again, we're still polishing all the type curves of this entire play. It's fair to assume, we'll probably have a flatter production profile based on the way we're producing the wells.
And how that's going to look in the end, please give us a little time because our engineering team is literally watching this daily. But we're learning a lot as we go here.
Joel K. Havard - Hilliard Lyons, Research Division
So could you just -- So is your expectation that will be fairly flat for how long? And then is it -- are you seeing in decline now?
Or is it really keeping flat here.
Barton R. Brookman
I would classify the production as flat. And we have tremendous pressure on this wellbore.
So we're very encouraged about where this is pointing reserve-wise. But again, we're just a couple weeks into this.
So we really -- before and I jump out of here -- and I think we're going to give more update possibly in December on this and definitely at Analyst Day. I know one of our goals is to be able to sit and really map the type curves for the Utica in these different areas.
And this is very complex because literally, over about a 20-mile range, you've got your liquid mix floating from 80% to a dry gas play. And the production characteristics in the shape of the curves in the way operators are going to produce those wells is going to vary across that 20 miles.
So again, Joe, please be patient, but over time we're going to deliver all this data up to the market.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
That's helpful Barton. And then in terms this well is a bit less productive, I mean, it's constrained, little less productive and also less liquids than your prior wells.
So are you expecting Washington County to have a lower liquids content versus up north?
Barton R. Brookman
Well obviously, the Garvin is lower liquid content. We expected some of that.
It's 400-foot deeper than our Detweiler well. So I think we expected 55% to 60% liquids on this.
But we expect the liquid mix to dramatically increase, as you go west in Washington County. So by mid-December, when we announced the Neill, I think the market is going to get a pretty good perspective of how this, in Washington County the very eastern portion is going to be pretty gassy.
The western portion is going to have a lot of liquids.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Got you. And then could you just remind us of the chokes on the other wells that you have already?
Barton R. Brookman
Well, they're only, if you go back to the press release, I think they were 22 and 26, Joe. But I know if you go back to the press release, when we announced them, I'm looking at this, we had a 26/64 on the Onega Commissioners, and we had a 20/64 on the Detweiler.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
But 1 difference here is your just more pressure with this Garvin well?
Barton R. Brookman
I don't want to say we have more of reservoir pressure. We have more working pressure on the wellbore because the gas content of the well is higher.
Joel K. Havard - Hilliard Lyons, Research Division
Got you. So the initial production of the Neill well, are you seeing the same liquids content?
Barton R. Brookman
Too early to comment, were still bringing a lot of frac load back.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Got you. And then just you gave a theoretical production if you open the choke, could you give us kind of a theoretical rate of return on this carbon well?
Barton R. Brookman
You tie to the reserves, too early to jump all over that one.
Operator
Our next question comes from the line of David Beard of Iberia.
David E. Beard - Iberia Capital Partners, Research Division
A question just on the Utica, specifically, down on the Washington County relative to takeaway capacity, just talk a little bit about your ability to sell liquids or get a time recovery on the Garvin and Neill wells specifically, and maybe your outlook for 2014 production potentially coming out of that region.
Lance A. Lauck
This is Lance, let me talk first about the takeaway from the southern Utica area. As you know, both our Garvin and Neill pads are connected to Blue Racer.
That's a joint venture between Dominion East Ohio and Cayman Energy. And they have substantial capacity for takeaway out of the area.
And so presently, our wells are connected to them and as Bar talked about earlier, as the Garvin-2H and 3H come online, we already have the connections in place for the Blue Racer such that we can bring those wells right into sales after the rest period. The same is true of the Neill, as we look to drill additional wells, out on the Neill pad over time, we have also all of the facilities set up there with Blue Racer well.
So from that standpoint, our takeaways is good to the south and we have been working very closely with Blue Racer, and things have been operating very well for us.
David E. Beard - Iberia Capital Partners, Research Division
Okay and just as a follow-up on a different topic, different type curves and the EUR curves for the Utica, I know you'd put out a very general type curve. Do you care to share your thoughts about what you'd see in the Utica or Northern or the Southern and if not now, when would you feel comfortable giving update to type curve?
Barton R. Brookman
We'll be comfortable sometime in the first quarter and our goal is by Analyst Day to really break out some type curves, probably being driven by the area north and south and also the liquid mix, David. Right now, general feedback from our engineering teams, our wells are performing in between the 2 type curves we published the 500,000 to 750,000 barrels.
The Stiers pad as I noted, is performing extremely well given the limited production and the pressure data we're gathering. But it's very early in this overall play and the big thing we need is some reliable midstream that we can deliver into.
So we're sticking with the 500,000 to 750,000 right now. And expect more here over the next several months.
Operator
Our next question comes from the line of Jeffrey Campbell of Tuohy Brothers.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
A lot of my questions have been answered, but I got a couple I'll lob in here, 1, with regards to going back to the way that the high-pressure wells are being produced, are they going on artificial lift immediately or will they go on artificial lift at a determined point in time, or have you really looked at that yet?
Barton R. Brookman
Jeffrey you're referring to Utica.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Like the Garvin well. Right.
Something like Garvin well.
Barton R. Brookman
I would not anticipate the Garvin well is going to be on artificial lift based on the liquid mix. I would anticipate, when you're in the 65% to 75% to 80% liquids, we'll have some considerations, most likely some type of plunger lift.
Plunger lift mechanism that we will be looking at to help lift the wells. And then if you go over the 80% liquids, I think operators may be looking at some type of rod lift or some other means, so yes, there will be a threshold on that liquid mix and artificial lift will be required.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
And another question I had was, what are your acreage holding requirements in the Utica in 2014? And I guess can you think about where that's going to take you with your acreage?
Gysle R. Shellum
Our acreage right now, everything we have been leasing, 57% of our acreage is HBP, first of all. And what we have been leasing is a 5-year primary with a 5-year option.
And so we've only been in the first year of that. So we still have 4 years of primary left before we have to worry about the option.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
So you basically drill where you want to?
Gysle R. Shellum
Exactly, we don't have any requirements or constraints at this time.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Another question I had was just kind of doing some quick math, it looked like that at your Utica wells, you're spacing clustering your fracs will be closer together than you're doing in the Wattenberg and I was just wondering, closer spacing, something that you would still experiment with the Wattenberg or have the completion techniques sort of stabilized now and just you've kind of got a recipe and you're going to follow it?
Barton R. Brookman
Yes, they're not dramatically different. But I would classify the Wattenberg as stabilizing yes.
Our teams there still have -- learning a lot with Microseismic and tracers and definitely with these downspacing initiatives. We are very, very in tune with what's going on with the fracs.
But overall, as far as fluids and spacing of our sleeves and things, we're not making big changes. We're probably in more of a steady-state mode with minor technical innovations going on.
The Utica, I would classify as dramatically moving up the learning curve on our completions. And I think this is probably true of all operators.
It's a new play, it's probably what you guys would expect. So yes, we're learning.
We're learning from our peers, we're learning from the service companies, we're learning from the Microseismic. We're learning from some tracer data that we are just understanding how the laterals are producing.
So there's a variety of things -- the Microseismic probably more than anything has helped our team in defining the optimum spacing on the Utica. So probably two different life cycles on the 2 completion techniques.
And expect more changes in the Utica, I think over the next year, you'll see continued improvements there.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
That was helpful. And let me ask one final question in returning to the idea of resting in Utica, one of your peers further to the north released some result in September of both condensate and wet gas wells that had not been rested at all, and the results were pretty decent, so I was just wondering, is that an end goal that you can even see at this point that maybe eventually you get to the point where it would be a pretty short resting period or maybe no resting at all, do you think that might vary depending on the geology where you're at, or what do you think about that?
Barton R. Brookman
Our end goal would be to not rest them at all, if we have the technical data to support that. So if we continue to gather information that supports no rest period, you will see PDC migrate to that point.
It helps the economics on the well. I think the big driver of rest period, no rest period is going to be where you're at in the wet gas window.
I don't -- I'm not sure on the dry gas side, if it's that required. I think you're going to have a lot of relative perm to the gas and I think the wells will produce fairly, fullbore right out of the blocks and as you go into the retrograde portion of the reservoir, I think there's probably more to be learned there.
So that's a pretty big answer. But we just have a lot of things we're still learning on.
Operator
Our next question comes from the line of Jason Smith of Bank of America.
Jason Smith - BofA Merrill Lynch, Research Division
Just going back to the Wattenberg. I think your 3P is based on 12 Niobrara and 4 Codell.
But Waste Management was 10 and 6, so with the success you've seen of the Codell all so far, how should we think about the mix of your 16 well pads going forward, was there something more specific about Waste Management that made you do 10 and 6 there?
Lance A. Lauck
This is Lance, our 3P is based on the 12 Niobrara and the 4 Codell, I think where we're positioned within the Waste Management, within the overall core as a play. We thought an opportunity to test the Codell with 6 wells in that area.
And based on geology across the whole core of the play, there will be some differences as far as how many ultimate wells were in the Niobrara versus ultimate how many well were in the Codell. But overall, the 16 wells per section is what we are very encouraged about by the early results from the Waste Management.
But that could change a little bit based upon geology throughout the core of the play.
Barton R. Brookman
And Jason, one thing on the Waste Management project, we didn't have any vertical Codells to drill among. So I mean, that was an undrilled section fortunately, that we were able to go in and test this.
As we go into the inner core, definitely, and the middle core, where the Codell has been aggressively developed on a vertical basis and refrac-ed, we'll probably be a little more cautious with the spacing and a the number of laterals that we place there, recognizing that there's been some pretty aggressive development. So we had a little more flexibility on the Codell side in the Waste Management.
But to the 3P side, I know our reserve team right now is really looking at -- we've got 2000 locations total in our 3P, and I know right now, based on some data we've got, we're looking at possibly upping that number. We're still in the review process of that, but some things -- some of the data we have we're pretty encouraged by.
Jason Smith - BofA Merrill Lynch, Research Division
And then where are you guys planning, and so this is Waste Management I think it's on the southeast part of the play, where is the plans for the next 16 well pads?
Barton R. Brookman
Well, again most of our development plans in '14 are migrating to a much more aggressive, somewhere around '16. We've got a few permits I think they're early in the year that may be slightly less.
I think the team is trying to amend some of that. So expect the company to really be striving for that type of spacing in some of form or fashion as we go forward.
Jason Smith - BofA Merrill Lynch, Research Division
I'm sorry, but I meant geographically where within the play?
Barton R. Brookman
Across the entire field, Jason. We will -- again, our core acreage has Codell 100% of it.
Lance A. Lauck
I think what you're asking, we focus is primarily has been on the outer core, because we had higher liquid mix. As we've got the kolkata plant now up and running, we're going to move toward more into the middle.
And even that inner as well as the middle.
Jason Smith - BofA Merrill Lynch, Research Division
Now that plant's up and running and you have several of the Waste Management would you be willing to share what current production is in Niobrara?
Barton R. Brookman
Current production today in the Niobrara?
Jason Smith - BofA Merrill Lynch, Research Division
Yes.
Barton R. Brookman
I don't have that number of the top of my head, Jason.
Operator
Our next question comes from the line of Michael Scialla of Stifel.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Bart, you mentioned the higher GOR in the Codell, was that limited to the Waste Management pad? Are you seeing that kind of across the play?
Barton R. Brookman
We're seeing that across the play, Codells performing in the same wellbore, the same area, a little gassier than the Niobrara again, the operating engineering teams think it's just a -- the permeability of the Codell relative to the Niobrara. We're getting a little bit better gas flow to the rock.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
So that 75% liquids that you're showing there, that's the have an estimate of where that's going? For you type curve?
I think your type curve is 75% liquids for Codell?
Barton R. Brookman
It probably is going to be a little bit gassier, and I can promise you that, that was our early Codell we developed that type curve, and that's clearly going to get gassier as we start developing the Codell in the middle and the inner cores. You'll see that number, in the inner core you'll see that number approach probably 45%, 50% liquids.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay. And did you see, on your vertical wells, do you have a good handle on with the GORs there for the Codell wells or is it too hard to decide for what's the -- I know a lot of it co-mingled with the Niobrara?
Barton R. Brookman
Yes, I think your second point, I'm not sure I've ever seen a study on that, and most of them are co-mingled zones, which are really tough for us to go back and I haven't seen a study of trying to evaluate that. I can tell you this Mike, it's only -- we're dealing with a few 2 or 3 points different in the GOR.
So this isn't a dramatic shift. Just enough to add a little more gas to the overall production In Wattenberg.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Got you. Okay.
Was curious on the Devonian sale, how much production's associated with that, do you know?
Gysle R. Shellum
So Mike on the Devonian itself, the net production, the PDC Energy is about 5.1 million cubic feet per day. Overall, and it's almost 100% dry gas.
The reserves, as of year end 2012 was about 12 bcf net to PDC Energy.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
I don't want to preempt your 2014 CapEx plans, I guess you're going to get that in mid-December, but just conceptually, you're having great success In Wattenberg and gaining confidence in Utica, as you look to 2014, with gas prices where they are, is it possible that you might not be drilling in the Marcellus at all next year?
Barton R. Brookman
Marcellus is in the joint venture of PDCM. And so we don't -- it really lives within cash flow and its own borrowing capacity with its own credit facility.
It's an LLC. So we don't budget that as part of our budgeting process.
It's done at a different level. So what we're looking at, our budget for PDC will really focus on the 5 rigs in Wattenberg, and 2 rigs in the Utica.
And whether or not that rigs keep running and the PDCM is really based on its cash flow and we're not anticipating adding cash to that program.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay, will that budgeting process take place the same time with the PDCM or is that going to come at a later date?
Barton R. Brookman
It's about the same time.
Operator
And we have a follow-up question from Ipsit Mohanty of Canaccord.
Ipsit Mohanty - Canaccord Genuity, Research Division
Almost all of my questions are answered, the only quick clarification on the Stiers wells. Bart, have you decided on choke side, is it going to be similar to that Garvin given just slow it at 20/64 or are you still evaluating?
Barton R. Brookman
I think the team is still evaluating that, and some of that will be based on how the pressures respond when they're opening the choke. So first thing we need, Ipsit, is to get the flexibility to produce more aggressively.
We're currently flaring, I think about 30% to 50% of the gas producing from the well. So we've got to get the midstream solution in place.
MarkWest is a week away. And once we have that, the team will work the choke up and make decisions based on the data we observed.
Ipsit Mohanty - Canaccord Genuity, Research Division
And my last one is more of a big picture, as you go forward in Wattenberg you add rigs end of the year, and sometime in '14 and you develop that area, is it all going to be kind of like 16 well pads, or are you going to do some one-offs in the Codell as well?
Barton R. Brookman
We'll be doing -- yes, we will be doing, every rig will be doing the blend of Codell and Niobrara, if that's what you're asking. We move into an area and we will develop out both zones from that pad to the most aggressive downspacing that we have technical support for.
Ipsit Mohanty - Canaccord Genuity, Research Division
And all will be on pads?
Barton R. Brookman
Yes sir.
Operator
Our next follow-up question comes from Ryan Oatman of SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
One final one for me, looking at the LOE, does look like it's going to go that about $1.50 per barrel, 4Q over 3Q on the higher production. When I look at that number going forward, how should I think about that if Devonian goes away, if the horizontal program continues to ramp in both the Utica and over there in the DJ.
Is that 4 33, is that a fair number to think about going forward, or you think it goes up or down?
Barton R. Brookman
Ryan, I hate to do this to you, but we have to Finnish -- first, we have to finish the transaction in the Devonian. That absolutely will help our overall lifting cost, we have to finish our budget, get approval by the Board, understand where we're adding wells next year, and how the production's going to grow.
So we've got a lot of moving parts there. I can tell you this, the 5 level is a good target.
Under that, I would expect next year, we're going to be under the 5, based on some early numbers, but how far below 5 we go, I think it's too early for us to jump out here and commit to anything.
Gysle R. Shellum
Yes, I agree with that.
Barton R. Brookman
So if you can be patient for another couple of months on that one, we'll be able to provide some more data.
Operator
Our next follow-up question come from the line of Irene Haas from Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
I have 2 questions. Is it my perception that as you go towards the south and part of the Utica trend, your wet gas condensate belt gets narrower is that a function of sort of steeper gradient to the top of the Utica, my second question has to do with your Garvin well, is there any structural influence because there are some old oil fields -- some really old oil fields from the northern part of Washington County, is there a structural influence, and then similar vein, is the lithology at Garvin different from your other wells, say Palmer, is it anymore, more like Garvin A.
Barton R. Brookman
Okay. So 3 questions, the first part of this is the liquid window narrowing?
It's too early to tell. We believe it probably is shifting from original opinions, a little bit to the west and whether it's narrowing or not will really be dependent on probably our Neill well and how it comes on and produces.
The second question is around the structure influencing the conductivity or the calculated perms. Based on seismic, we reviewed, I would answer that question, yes.
We have some structural issues, some faulting issues that are definitely influencing the area. The third question about the lithology, there's absolutely a carbonate content increase in the Point Pleasant member that we have observed as we go in south in the play that changes rock property slightly.
Can act is creating a more brittle rock, which may be something with a structural influence that may be enhancing the conductivity of the well. So Irene, those are very high level, general answers of what we're seeing, nothing I don't think the market doesn't understand out there, because it's all supported by public data, geologically and what's out there.
So hopefully I answered your question.
Operator
And our last follow-up question comes from the line Jack Aydin with KeyBanc.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
On your Page 14, did you, is there any of the C-bench wells included in that type curve?
Barton R. Brookman
In the type curve?
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
Yes, well, yes, I mean I'm looking, if any of that production, your production from the C-bench is included in your more or less the red line that you're showing?
Barton R. Brookman
The actual performance that we are showing there is 2 C-bench and 2 B-bench. 4 Niobrara wells, and Jack, I don't know if you can see it, all 4 wells are highlighted in the light gray.
You can see they've all migrated into kind of the same area. But yes, 2 of them are C and 2 of them are B.
Operator
And I'm showing no further questions at this time. I'd like to turn our call back over to Mr.
Trimble for any closing remarks.
James M. Trimble
Well, thank you, I just wish to thank everyone for your participation today. I think we had a very exciting quarter.
And thanks for calling in.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program.
You may all disconnect. Have a great day, everyone.