Nov 6, 2014
Executives
James M. Trimble - Chief Executive Officer and President Barton R.
Brookman - Chief Operating Officer and Executive Vice President Gysle R. Shellum - Chief Financial Officer Lance A.
Lauck - Senior Vice President of Corporate Development
Analysts
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division Joseph D.
Allman - JP Morgan Chase & Co, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Irene O.
Haas - Wunderlich Securities Inc., Research Division Ipsit Mohanty - GMP Securities L.P., Research Division Michael A. Hall - Heikkinen Energy Advisors, LLC Brian M.
Corales - Howard Weil Incorporated, Research Division Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Operator
Greetings, and welcome to the PDC Energy 2014 Third Quarter Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.
On the call today, Mr. James Trimble, Chief Executive Officer of PDC Energy.
Joining Mr. Trimble on the call is Mr.
Barton Brookman, 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, Mr.
James Trimble. Mr.
Trimble, you may now begin.
James M. Trimble
Thank you, operator. And good morning, everyone, and thank you for joining us today to discuss PDC's Third Quarter 2014 Results and Operational Update.
As she stated, with me today is Bart Brookman, our President and COO; Gysle Shellum, CFO; and Lance Lauck, Senior Vice President, Corporate Development. Before I begin, let me draw your attention to our safe harbor language at the beginning of our presentation that will cover any forward-looking statements made today during our presentation.
PDC had a great third quarter with accomplishments including Wattenberg's continuing to perform with the 5 drilling rigs running, we expect production to ramp as we exit 2014. In the Utica, we turned in line the Palmer wells in Morgan County in early September, which demonstrated the viability of our Western Utica acreage.
Subsequent to the quarter end, we increased our revolver to $700 million, closed the sale of our Marcellus interest, with approximately $150 million in cash proceeds and signed preliminary settlements that covered 24 of our former partnerships with just 4 partnerships remaining. Bart and Gysle will cover more detail on these in the third quarter.
As this will be my last earnings call in which I will participate, as I'll hand the reins to Bart at year-end as CEO. Next quarter, I will be listening as a board member.
So I wanted to take this opportunity to take thank our many investors who have supported us during my tenure as CEO over the last 3.5 years. We have made many significant changes during this time, all to focus PDC's assets and efforts on 2 liquid-rich areas and ultimately to deliver value to our shareholders.
It has been my honor to lead this fine group of employees, from the management to our office personnel and to our dedicated teams in the field. I will miss the day-to-day interaction with both employees and investors, but I look forward to returning to PDC's Board of Directors and to occasionally when our paths cross again.
I will now turn the call over to Bart for quarter highlights and an operational update. Bart will be followed by Gysle who will cover financial details.
Bart?
Barton R. Brookman
Thank you, Jim, and hello, everyone. So here we are, once again, reminded we are in the oil and gas business.
Natural gas prices at a $4 per Mcf level and oil pulling back to near $80 a barrel. But PDC couldn't be more prepared for these times.
We have made significant efforts in the last 2 years to mitigate these risks. And our current growth strategy and ability to deliver value to our shareholders is solidly in place based on several factors.
First and foremost, our crude oil and natural gas hedges that are in place. Through year-end 2015, we have 75% to 85% of our forecasted volumes hedged at approximately $89 a barrel and $4 in Mcf.
These hedges help insulate the company from large cash flow swings in 2015. A $10 movement in oil prices will only move the company's 2015 anticipated cash flows by $20 million to $25 million.
Second, after the sale of our Marcellus assets is our strong liquidity and balance sheet. Currently, we have liquidity of just under $800 million and an estimated year-end 2014 debt-to-EBITDA ratio of 1.6 to 1.7.
Third, is our strong portfolio of projects in the Wattenberg Field and the Utica Shale. In the Wattenberg, our Niobrara and Codell projects at $80 oil prices are expected to deliver between 30% and 75% returns on drilling.
And last, our acreage is largely held by production. We maintain excellent operational flexibility with our capital programs as we continue to evaluate the commodity market.
Let me cover some highlights of the third quarter 2014. From continuous operations, production for the company increased 60% over third quarter 2013.
The company's overall liquid mix was 65%, over 45% of this total mix being oil. In the Wattenberg, production increased 60% from third quarter of 2013 to 23,400 barrels of oil equivalent per day.
For the quarter, nonoperated production was 3,400 barrels of oil equivalent per day or 15% of the Wattenberg production. Product sales for the company were up 56% from prior year 2013 to $121 million.
Adjusted cash flow from operations was $56 million, and if we exclude the impact of the litigation charge, adjusted cash flow from operations would have been approximately $72 million. And last, we closed on the sale of our Marcellus assets in October, $190 million net proceeds to the company, $150 million in the form of cash and $40 million in the form of a note.
This gives us tremendous financial flexibility as we continue to develop our Utica and Wattenberg fields. We're very pleased we have reached preliminary litigation settlements on 24 legacy partnerships and only 4 partnerships remain.
Next, let me give a detailed operations update for the company. Again, third quarter production from continued operations was 25,600 barrels of oil equivalent per day.
Again, we have stripped out the Marcellus production for the full year 2014. With the Marcellus production included, the quarterly production would have been 29,400 barrels of oil equivalent per day.
Again, a production improvement on a quarter from continued operations of 60% when compared to the third quarter of 2013, Wattenberg production, 23,400 barrel of oil equivalent per day, 92% of the company's production. And our Utica production was 2,170 barrels of oil equivalent per day, 8% of the company's production.
Some production highlights. A really terrific performance by our operating teams.
The fifth rig was deployed in the Wattenberg Field in mid June and will soon begin contributing to production. And the Wattenberg, again, 23,400 barrels of oil equivalent per day, 60% growth.
Our nonoperated production was again 3,400 barrels of oil equivalent per day, 15% of the basin's production. And we continue to see a very strong pace of nonoperated projects.
Line pressures for the quarter were slightly elevated from prior year levels, but were reasonable overall and we forecasted them appropriately in our guidance. The downspacing projects are on schedule for 2014, and we're very pleased in the Wattenberg, we had our first production from an inner core location which is gathered by Aka Energy, these are the Ram Land wells, a 7-well pad again in the inner core portion of the field.
And in the Utica, our Palmer 2-well pad came online 2 months ago with very encouraging results. Currently, we have no midstream restrictions on that production, and I'll give a full update on these wells in a moment.
And in the Utica, we expect first sales on our Dynamite pad, which is in the northern part of our Utica acreage sometime in December. Currently, we are completing this pad.
163 frac stages are planned for these 4 wells. Overall, for the quarter, as you can see from the pie chart, our third quarter commodity mix, 65% liquids, again, 45% of the company's production now oil based.
To give a quick update on our production guidance, really no changes from our overall forecast, but our guidance now reflects 2014 pro forma volumes from continuing operations where we will be removing the full year 2014 Marcellus production. Let me quickly walk through this.
If you start in the middle graph, the middle bar, 2014 revised guidance, announced in the second quarter, as 10.4 million to 10.6 million barrels equivalent. By removing the first 9 months of production from the Marcellus of 1.1 million barrels equivalent, we have guidance going forward of 9.3 million to 9.5 million barrels, and that is the production related exclusively to our Wattenberg Field in our Utica operations or continued operations.
An update on some key technical initiatives in the Wattenberg Field. The attached map outlines areas for extended reach laterals as highlighted in orange stars.
Downspace projects is highlighted in the blue stars. And different completion designs is highlighted in the green stars.
Let me start with the extended reach laterals. PDC has executed and participated in a series of extended reach projects across the Wattenberg Field.
PDC will complete over 20 of these by year-end 2014. To date, our operating teams are observing very strong production performance and expect a 30% to 50% improvement in overall reserves per well.
In 2015, I am happy to announce that 40% to 50% of our drilling will be modified to extended reach laterals. Again, all based on the very encouraging results related to these horizontal drilling projects.
Next, let me touch on the downspace projects. Several projects are underway at 20-well equivalent per section.
These are on schedule for 2014, and our 2015 tests are on schedule throughout next year. Production data from these projects should start early 2015.
And by year-end 2015, we expect to better define the next layer of downspace opportunities in the Wattenberg Field. And then on completions.
A series of things happening here. First, slick water jobs versus hybrid jobs, sliding sleeve versus plug-and-perf, fluid design changes, chemical add changes, different surfactants are being tested, and last, stage-length modification.
Among all of these tests, we have one firm conclusion that will be included in our 2015 budget. Our stage length is being modified to 200-foot per stage length or 5 stages per 1,000 foot of lateral.
The balance of 2014 and all of 2015 completions are currently being modified for this completion design. We are seeing strong production and reserve enhancement of approximately 10% based on this completion design.
In 2015, we will also be testing a series of completions at the 150-foot stage length. Again, overall, a series of different things happening here in completions that are being tested, and we will continue to communicate with the market on how these advancements are delivering improvements in production and reserves as we gather more data.
Let me bring everyone up to speed on our Utica project in Eastern Ohio. Again, 67,000 net acres in this play, 2/3 in the wet gas window, 1/3 in the condensate window.
Currently, 350 horizontal locations in inventory. We added a top hole rig to our operations in July.
Currently, we are drilling the horizontal portion of the coal pad in our northern acreage and we are winding down on the completions of the Dynamite pad in northern acreage and we expect first sales from this pad sometime mid December. We also have 113-square-mile 3D shoot [ph].
We expect to have data on that back in the first quarter of next year. And our planned spud counts are 18 wells, including 6 from the top hole rig and 8 wells will be turned online this year.
Let me bring everybody up to date on the 2-well Palmer pad in the southwestern portion of the Utica acreage. Very encouraged by early production from this pad, which de-risk the southwestern portion of our acreage, 8 weeks into production for both wells.
Each well is producing at a 600 barrel of oil equivalent rate on an 18/64s choke. We have stair-stepped the production up slowly over the past 8 weeks from a 12/64s to an 18/64s, and both wells are exhibiting stable casing pressure of approximately 2,000 PSI.
I should note neither well has exhibited any significant declines, and the liquid mix for both wells is approximately proxy 70% liquids and 30% dry gas. So both wells are in the condensate window and further support phase behavior windows that we have defined.
The pressure gradient for this area is 0.65 PSI per foot. And last, we are very encouraged by some early data on slick water completions.
One well here was completed with a hybrid design and one well with a slick water design. We're gaining some very significant technical data from both completion designs, which may spur some considerable cost savings in the future.
Drilling for the quarter. Again, we record both spud and turn-in-lines to reach -- represent the pace of drilling for the company.
From the bar graph, you can see we turned-in-line 11 wells for the quarter with an expectation of 18 wells. This 7-well shortfall comes from all 7 wells in the Ram Land pad, which is our first drilling in the inner core portion of the field.
Those wells were scheduled for third quarter but actually came online in early October. Year-to-date, spud counts by area.
86 spuds in the Wattenberg, 8 spuds in the Utica. And we have participated in 71 nonoperated horizontal spuds with an average working interest of approximately 22% for a total of 165 drilling projects for the year.
Overall, we are on target for our 221 planned projects, approximately 140 of those will be operated PDC horizontal drilling projects. Our current drilling activity for the fields: 5 rigs in the Wattenberg and 2 in the Utica.
An update on our lease operating expenses. For the third quarter, total lifting cost came at $4.56 per equivalent barrel, right in line with our overall guidance.
Several movements in the LOE area to discuss. Labor costs in the basin have been growing primarily due to demand pull across all services, drilling, completion and production.
We also have compression costs that have escalated due to the ongoing increase in air emission regulations. And third, we did have less work over activity in the third quarter, which contributed to a slight downtick in our overall lifting costs.
For the balance of the year, you can see from the graph, we expect lifting costs to be maintained just above the $4 level. And as we go through 2015, expect improvement in this overall measurement as we dramatically improve production.
An update on our capital budget. When adjusted for continued operations, the budget is now $637 million, which excludes the $11 million we spent on the Marcellus.
We are right on target for the $637 million. $443 million of that in the Wattenberg and $192 million in the Utica for drilling, completion and leasehold acquisition.
Again, on target for the $637 million. So some highlights.
Wattenberg. Third quarter net production of 23,400 barrels of oil equivalent per day.
Operated production, 85% of total Wattenberg through 9 months 2014 and 55% of the operated production is now from horizontal wells. We drilled 13 horizontal Niobrara wells in the third quarter.
We drilled 18 horizontal Codell wells in the third quarter. Our first inner core production was established on the Ram Land pad.
We're extremely encouraged by the production levels from those 7 wells. The 20 longer lateral projects planned for 2014 are on pace and the longer lateral projects are becoming a bigger part of our drilling program in 2014 and going forward.
In the Utica, 67,000 net acres, 350 locations in this project. The majority of our acreage is in the liquid-rich window.
And we have focus right now on bolt-on acreage opportunities. Continued strong production from our wells, 15 wells currently producing.
And the drilling and completion cost structure in the Utica right now, $9.5 million for a 6,500-foot lateral. With that, I'm going to turn this over to Gysle for a financial overview.
Gysle R. Shellum
Thanks, Bart, and good morning, everyone. As a reminder, my comments will be high level.
So for a more complete analysis of our third quarter this year, please see our press release and 10-Q, which we filed earlier this morning. Third quarter was another very solid quarter for this year.
Total net production for the quarter was 2.7 million barrels of oil equivalent, which was up 57% from the third quarter of 2013. Production from continuing operations in the quarter was 20 -- 2.35 million barrels of oil equivalent, which was up slightly from our second quarter production of 2.31 million BOE, which was what we expected.
As Bart discussed, we had only 18 wells scheduled for turn-in-line this quarter. Included in those 18 wells was 1 7-well Wattenberg pad scheduled for September turn-in-line that was delayed and came online in Q4.
Nonoperated production was closer to our expectations this quarter. We accounted for the October sale of our joint venture interest as discontinued operations in the third quarter, so results from our share of the joint venture are not included in sales and costs in the summary GAAP financial results, but they are included in net income numbers from all operations.
Look at the numbers. Sales from continuing ops for the third quarter were a little over $120 million, a 56% increase over the third quarter of 2013 and a slight decrease from second quarter of 2014.
The increase compared to the third quarter last year was due to higher production while weighted-average commodity prices dropped a couple of percent. Average price per BOE of $51.24 in the third quarter this year, plus 2.4% lower compared to the third quarter of 2013, driven by crude oil prices, down 14%.
That drop was offset by natural gas prices, up by the same percentage. These prices do not include settlements on derivatives that we formerly called realized hedge gains and losses, which were negative about $4 million in the third quarter of 2014 compared to a negative $2 million in 2013.
Production costs increased about 34% quarter-over-quarter as a result of increased production. Production costs include lifting cost, taxes overhead and beginning this year, a separate line item for fees associated with gathering, transportation and processing, specifically for the Utica and Marcellus areas.
In the third quarter 2014, production costs averaged $9.67 per barrel of oil equivalent, $1.90 or $0.16 lower than the third quarter last year. For the second quarter 2014, we averaged $9.90 per BOE, so we were down $0.23 per BOE Q2 over Q3.
Lifting costs on a per unit basis were down 6% in the third quarter '14, compared to the third quarter of '13. The comparative numbers for last year are all adjusted for the change in presentation from gathering, transportation and processing costs.
Gross margins were 81% of sales for the third quarter compared to 78% for the third quarter 2013, which reflects the increase in average prices before realized hedge gains and losses. Increased liquids production as a percent of total production and lower production costs contributed to a slightly improved margin.
Second quarter 2014 margins were identical at 81% of sales. DD&A includes depreciation of fixed assets and depletion of oil and gas properties.
DD&A in the third quarter was up a total -- was up in total on a -- and on a per OE [ph] basis due to increased production and slightly higher rates. Depletion rates on oil and gas properties only, excluding depreciation, were $21.09 per barrel of oil equivalent in the third quarter of '14 compared to $18.33 per BOE in the third quarter of 2013.
G&A costs were up in total and on a per unit basis primarily due to litigation charge of $16.2 million related to preliminary settlements on 2 separate cases that covered 24 limited partnerships. Approximately $7.4 million of the expense related to an alternative proposal to plaintiffs in a class-action lawsuit that covers 12 partnerships that we discussed last quarter.
The remaining $8.8 million is for a preliminary settlement reached with investors on 12 other partnerships that are in process of litigation through bankruptcy proceeding -- process of liquidation through bankruptcy proceeding. PDC is General Manager of 4 remaining partnerships after these cases are settled.
Net income from operations and net income reported for the quarter per GAAP reflect the impact of change in market value of our hedge portfolio during the quarter. The value of our oil and gas hedges increased $95 million pretax during the quarter as a result of declining futures prices in both commodities.
That increase in market value is included in net income as gain on unsettled derivatives. We eliminate the impact of unsettled derivatives and comparing the results to prior quarters as presented on the next slide.
This slide presents non-GAAP financial information that is reconciled to GAAP in our 10-Q and press release filed earlier today as well as in the appendix of the slide deck. Additionally, we have shown the impact of the litigation charge I just mentioned on August net income -- on adjusted net income and adjusted cash flows from operations.
Adjusted cash flow from operations is defined as cash flow from operations excluding changes in working capital. The upward trend here reflects the production volume growth that pushed oil and gas sales higher for the periods presented.
Adjusted EBITDA in the current quarter was up 41% compared to third quarter 2013 and flat from second quarter 2014. As Bart discussed, when you normalize EBITDA by removing the litigation charge, adjusted net income would be approximately $4.3 million or about $0.12 per basic share for the quarter ended September 30, 2014.
Adjusted cash flow from operations would be about $71.7 million or about $2 per basic share and $1.75 per fully diluted share. Turning to the balance sheet.
Our revolver matures in 2018 and we've held the borrowing base at $450 million until our fall redetermination this year. Borrowing base increased to $700 million in October, but we elected to maintain the commitment at $450 million at this time.
With proceeds from the sale of Marcellus assets, we've paid off the revolver balance and expect to exit 2014 minimally drawn on the facility. The table on this page reflects PDC's consolidated borrowings at the end of the third quarter and prior to the October 14 closing of the Marcellus share -- sale.
Our pro forma consolidated financial statements no longer include our proportionate share of the Marcellus debt of $60 million as of September 30, 2014. Liquidity, including cash on hand and available borrowing base at September 30, 2014, was approximately $388 million based on a $450 million borrowing base.
Pro forma for the Marcellus shale and the increase of the borrowing base, our available liquidity would be $789 million. Our $115 million convertible debenture matures in May 2016 and our $500 million high-yield debt issue matures in October 2022.
Our hedge positions for 2014 and 2016 are shown on this next page. We have hedged substantially all of the oil and gas production we are allowed to hedge under the terms of our credit agreement for 2014.
For 2015, about 75% to 80% of our allowable production is hedged based on our year-end 2013 reserve report. We continue to work on adding 20 -- to 2016 positions and recently added some natural gas swaps and collars for 2015 and 2016.
Oil is hedged with a combination of swaps and collars with average prices in the high-80s. Our gas hedges are all in the $4 range and we settled at lower prices during the third quarter this year.
As you know, gas prices were depressed in Q3, however, prices have rebounded a little above $4 in the past few days as winter approaches. All of the gas hedges associated with the Marcellus assets were assigned to the buyer of the PDCM joint venture and are removed from the schedule in this presentation.
Overall, the quarter was in line with our expectations. We're sticking with our financial guidance that we presented in the second quarter call.
However, we think we're headed to the low end of that guidance for adjusted EBITDA, cash flow and net income due to the additional legal charge we took this quarter and weakening oil prices. With that, I'll turn it over to our conference host for Q&A.
Operator
[Operator Instructions] Our first question comes from Welles Fitzpatrick of Johnson Rice.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
After the nice wells at Ram Land, any thoughts about moving more into the inner core? Or do the line pressures still kind of push you away from that?
James M. Trimble
We have not modified our schedule for 2015 right now, but I do know this. I think we have 90 inner core locations in inventory.
I'm going off memory here. But I know over the next 2 years, Welles, that we -- I think we're scheduled to drill out all of those.
So obviously, with the returns in the inner core and the middle core, our drilling program in the Wattenberg will be more aggressively shifted to those 2 areas as we go through the next 2 years.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
Okay. Perfect.
And then if I could ask one follow on. The 40% to 50% extended reach in '15, does that -- is that 7,000 to 9,000 footers, or by extended reach, you mean kind of 9,000 to 9,500?
Barton R. Brookman
Oh, it's more or like the 6,500-foot reach, I think, on average that we...
Operator
Our next question comes from Joe Allman of JP Morgan.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Bart, on the completion designs, you seem to distinguish between the frac stage length and other different changes you're making in the completion. So, like -- have you drawn a conclusion that you're going to into 200-foot frac stage lengths but you're going to be testing the 150 foot as you said, but is that one parameter where you feel that you really -- that definitely will improve productivity?
And my second question on completion designs is, what's the implication of slick water versus hybrid? I mean, do you think even though you might have water handling costs or whatnot, do you think slick water is a preferred method, if you can prove that it's as good or better than hybrid?
Barton R. Brookman
Okay, so let me jump on the first one. What I try to do in the overall technical advancements is give everyone confidence in the 2 things that we've got firm data on that are going to enhance production and reserve performance, and that is the extended reach lateral and the stage length.
The teams -- and we are currently modifying our current practices and our 2015 capital budgets to incorporate those 2 technical improvements. So yes, I was trying to paint the picture that the 200-foot is a current practice and will be applied to next year and they'll keep testing the limits of this by going to 150 foot in future tests.
But the 150 foot is not a future practice. It's the next threshold of testing.
All of the other methods of completion, slick, plug-and-perf, fluid designs, we've got surfactant-based fluids we're testing, we've got a series of different surfactants we're testing. Our perforation schemes, some point focus perforation schemes that are being tested.
We've got a lot of things we're looking at. But the jury is still out on all those for PDC.
And as I said, we'll communicate back with the market when we get more data. I think at Analyst Day, we'll probably have clear updates on extended reach and the shorter stage lengths.
But I think a couple of these other components that I discussed we'll have some early data on. So back to slick versus hybrid.
Boy, Joe, and I could go on for probably a half hour on this one. Yes, there are implications and there are technical reasons that point you towards pull [ph].
Obviously, slick jobs are more cost effective. Prop and placement is less.
Generally, your carrying capacity of the fluids are less, your concentrations are less. And in many cases, you see a much less steeper early time decline.
So it comes down to an IP versus reserves and then in net present value on both jobs. Because the shape of the curve for a slick versus a hybrid can be different.
The hybrid jobs, obviously, are more expensive. You get better near wellbore conductivity.
And then you get into the whole debate of frac mechanics and the geometry of your frac. And that's the one that I think the jury is still out, particularly in the Niobrara.
So again, I'm probably not answering your question on that one, but it's very, very technical in nature. Our teams are learning a lot.
But I should note, this basin has a lot of experience in both of these completion designs. And there has not been a strong evolution to slick jobs in the last 20 years.
I can remember when we were attempting slick jobs 8 years ago on vertical wells. But there's been improvements in fluids and there's been improvements in surfactants.
And the horsepower we're putting on location is much more intense now. Our rates that we're gathering on our frac jobs are much more intense, so there's a lot of things that have changed.
So hopefully, I answered your question.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
That's very helpful, Bart. And you actually bring up another question.
So with the new completion designs, are you convinced that you're getting more reserve recovery and you're actually increasing reserves per well and not just accelerating production? And what are the ways that you can actually convince yourself of that?
Is it microseismic? Is it pressure data?
Is it the impact you're seeing on nearby wells? Or is there some other factors?
Barton R. Brookman
The answer is yes. We are convinced that we are enhancing reserves and adding value and lowering our drilling F&D costs.
And we have probably been more patient delivering this data back to the market because the answer to how do we know, we want longer-term data. Particularly in longer length laterals, if you use any type of choke management, you may see a slightly stronger IP, but you really want to watch your long-term declines.
And this is true of increased stage lengths also. So it's a combination of IP shape of the curve that all comes together for a different reserve profile, which is higher than the standard traditional 4,200-foot lateral that PDC had.
And the PV10 of the project per dollar invested is absolutely going up.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
That's very helpful. So just briefly on a different topic.
So I'm assuming that the litigation is essentially behind you. In your slides, you indicate that you got settlements on 24 legacy partnerships.
I thought that, that shoe line litigation -- I thought that only involved 11 or 12 partnerships. And so I know it was a class-action lawsuit.
So I just want to clarify, any limited partners who were a party to that shoe line litigation? I'm assuming that all of them, even -- not just the particular ones who sued you, but all of them are going to participate in that settlement.
So in other words, you won't have other limited partners coming at you, saying, "Hey, we want a piece of this action, too." And then, I just want to make sure that those 4 -- is there some legal principle?
Or is there some statute of limitation that will prevent other limited partners from coming at you and saying, "Hey, they got a good deal, we want the same deal, too."
Gysle R. Shellum
Joe, this is Gysle. I can't go into too much detail, because we still haven't finalized these settlement agreements.
But on the class-action suit, as in any class-action suit, any partner can opt out of the class and then they're on their own. And that event, the option for them to elect out has not occurred yet.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Okay, so then, am I correct that there were only 11 or 12 partnerships that are party to that shoe line litigation?
Gysle R. Shellum
Yes, there were 12.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Okay. And so your comment about the 20 settlement on 24 partnerships, can you help me with that?
Gysle R. Shellum
They were -- if you look at the 10-Q note contingencies, there was a -- 12 more smaller partnerships that were taken into bankruptcy to liquidate and there was an action brought very recently on those, that's also part of a preliminary settlement agreement. So it's just a coincidence that they're both 12, groups of 12 -- 2 groups of 12 partnerships.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Got you. And again, so and it's -- the 4 more partnerships, those are ones you bought out already or you've yet to buy?
Gysle R. Shellum
The remaining 4 are alive and well. We've done nothing with them.
Operator
Our next question comes from Leo Mariani of RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
I was hoping you could give a slightly more color around these Palmer wells. You cited a $9.5 million well cost.
Was that what you actually saw on the Palmer wells? And you also talked about 70% liquids, can you help us with the split there in terms of oil versus NGLs and what were the lateral lengths on those?
Barton R. Brookman
Okay, the lateral lengths are approximately 7,000 foot, Leo. The liquid mix was 70%, 30%.
I think we're 45% oil, 25% NGLs and put a plus or minus on both of those numbers and the balance of natural gas. And what was the first part of your question again?
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
And what were the actual well costs on those?
Barton R. Brookman
That one's actually a little confusing, Leo, because we had the well incident, the loss in control incident on the #1 well. So the time on location is very -- I can tell you normalized well cost for that 7,000 is probably going to be in that mid-$9 million range.
We had extra costs on this one because time on location with the drilling rig while we were working on the #1 well which we lost.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay, that's helpful. And I guess, can you also speak to some of your other kind of previous wells in terms of well performance, I guess, most notably, I'm thinking about the Garvin and the Neill?
Barton R. Brookman
Boy, the Neill, we're disappointed in, and I think we'd let the market know that one, I think, we've ended up 40- or 50-foot land -- landed 40- to 50-foot below the point [indiscernible]. Right now, is kind of on a forever 0-decline basis.
It's on a pumping unit. And kicking out 25 to 40 barrels a day, I believe.
And again, that has been disappointing. I think the thing to take from this is this Palmer proves the landing zone failure on the Neill.
We are seeing dramatically different production characteristics and permeability in this Palmer well. The Garvin wells are right in line with what we've talked about before, our prior presentations where we've got our wet gas window-type curve, we're right in line with that.
And the other wells in the play continue to support our condensate window-type curve. So again, we've only got 15 wells online.
These Palmers are the next big ones for us. And then we're extremely excited about this Dynamite pad to the north because we've made some significant modifications in our completion design there.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
That's really helpful. And I guess just in terms of plans for next year.
Obviously, oil prices have come in significantly, just kind of wanted to get your thoughts on potential reaction, in terms of what you would do with your capital spend with respect to the pullback in oil. And when can we expect to get kind of more complete detail around spending and production guide for next year?
Barton R. Brookman
Both capital spend production guide will be approved by our board in early December and announced mid-December to the market. Philosophically, we've already been out talking.
You'll see a more conservative approach, obviously, from the company. Six months ago, Analyst Day, we talked about a sixth rig in Wattenberg and a third rig in Utica.
I think a starting point would envision those being pushed very late in the year. And that will really honor our balance sheet.
I can say this, we'll still with the deployment of the fourth and the fifth rigs in the Wattenberg and the 2 running in the Utica, we still anticipate significant cash flow growth and very important tremendous production growth next year. With that, with the hedges, our cash flows next year are very, very predictable.
So -- but bottom line is yes, we're taking a much more conservative look, and we will continue to evaluate the markets, literally, week by week, watching oil and gas prices and make adjustments as necessary.
Operator
Our next question comes from Irene Haas of Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
I just kind of want to revisit the Utica again. So you guys got a good sense of tests coming out of Palmer and Garvin is cranking along.
Looking at next year, do you have any plans to do any more locations, sort of the north in Washington County area? And along the same line of reasoning, how many acres of your net acres of the 67 is in Washington County?
And how much -- really, what I'm trying to get is, how much more drilling you would need to kind of prove up the entire land block? And then lastly, why do we need 3D in this area?
Barton R. Brookman
What was last part of that question?
Irene O. Haas - Wunderlich Securities Inc., Research Division
3D, yes.
Gysle R. Shellum
Okay, let me start with the last. So 3D is going to be a very valuable tool in the southern acreage.
It's more active from a faulting standpoint. We believe we can add some additional value by managing around that.
And the Palmer 1 incident was an eye opener for us for the significant pressures that we can encounter, and the Palmer 1 was a mechanical failure on the VOP. But we realized that there are some significant drilling risks in this play when we drill through faults in some gas kicks.
So it's going to help us overall in the management of the play and hopefully optimize reserves. When you look at our drilling program next year, we've got the Dynamite pad coming on, we've got a coal pad that's currently drilling in the northern acreage.
Then we've got a slow migration. We go to the Miley pad, which is in Northern Noble County, which is kind of splits our southern and our northern acreage.
We'll start with, I believe, 3 wells on that pad and then we'll be moving down to the southern acreage. And we will hit the very center portion -- we've modified our drilling plans a little bit here, the center portion right on the border of the wet gas and the condensate window where we think the permeability and the returns are going to be optimized.
I believe the name of that pad is the Welch [ph] pad. So that would be between the Palmer and the Garvin locations.
That is a significant project that will be drilled as we go into first and second quarter of next year. Then we have a coal -- I'm sorry, we have a -- I'm going to grow -- growth pad in the southern portion of the acreage.
And then we'll migrate back up to the northern acreage and come back and drill the other 4 Miley wells. So to your question, yes, we are trying to delineate all the southern.
And northern Washington County is probably, probably 60%, I would say, of our acreage position. And we continue to get good quality data to support the quality of that acreage.
Operator
Our next question comes from Ipsit Mohanty of GMP Securities.
Ipsit Mohanty - GMP Securities L.P., Research Division
Let me stay on the Palmer well for a second and see if you can provide any color on why you used the 18-inch choke to start with, because as you know, a larger choke -- in other words, I was just wondering if it's guided by any early retrograde behavior that you saw there?
James M. Trimble
Yes, and we -- again, we started on a 12 choke on this well and we stair stepped it up, and just in the last 2 weeks upped it to an 18 choke. We did that strictly for pressure management because the early liquid mix, we recognized that we were in the condensate portion of the play.
So we were being very conservative in our pressure management on the well. The encouraging thing, we have very long laterals here.
We have very stable production on this. And we have very stable pressure profiles being exhibited from our casing pressures.
So that's intentional as far as our overall management of the wellbores and you will see PDC continue to do that, particularly when we're in the condensate portion of the play.
Ipsit Mohanty - GMP Securities L.P., Research Division
Okay, well so nothing to do with retrograde then?
Barton R. Brookman
Nothing to do with what?
Ipsit Mohanty - GMP Securities L.P., Research Division
With the retro -- any kind of retrograde behavior that you saw, or you didn't?
Barton R. Brookman
Yes, and we're in the condensate portion. So I think when you take phase behavior by traditional definition, you're in the retrograde region.
That is why we are managing the wells the way we are.
Ipsit Mohanty - GMP Securities L.P., Research Division
Okay. And then what kind of pressure decline have you seen in the last 60 days or so?
Barton R. Brookman
It's been on for 2 months, and it's been a couple hundred pounds. I mean, it's very, very minimal pressure declines.
Part of that is the length of the laterals. We have a lot of reservoir that's sitting there contributing long term to the production and pressure maintenance of the wellbore.
Ipsit Mohanty - GMP Securities L.P., Research Division
Okay, thanks. And then the last one on Wattenberg.
As you finish up your inner core and you're going to go into your middle and outer core, does the overall IE of the production, do you see that improving or kind of staying flat, because you've got Codell coming in with probably a higher [indiscernible] ?
Barton R. Brookman
Oh, boy, Ipsit. We're going to be in that 65%, and we'll give clarity on this in our 2015 guidance.
But we're going to be in that 65% to 70% total liquid mix, and condensate should be 45% to 50% total. Yes, as we drill out the inner, we're going to have more gas, but we have very strong liquid production from that.
But we still have a good portion of our drilling programs in that middle region. So overall, I think those are the ranges you can expect.
But we'll give -- again, we'll give more clarity as we finalize our budget.
Operator
Our next question comes from Michael Hall of Heikkinen Energy.
Michael A. Hall - Heikkinen Energy Advisors, LLC
I guess one thing just -- can you provide a little -- just comfort around executing on bringing -- you've got a pretty substantial number of wells planned to come online in the fourth quarter, 45 turn-in-lines. Maybe just provide a little -- what sort of color can you provide as to how you reached [ph] that execution through the quarter and also around the infrastructure in the DJ in that context?
Barton R. Brookman
Based on everything we know right now, and there's one significant pad in the southeastern portion of the field that is, I believe, a 16-well pad, and that's obviously a big portion. I think we're currently completing that pad and -- successfully.
So everything we know, our fourth quarter production guidance and our fourth quarter turn on schedule, we're on target. We've got very, very favorable weather in Colorado right now.
It's not -- we don't have snowstorms or mud or anything slowing us down. So the turn-on schedule in our production guidance for the fourth quarter, we've got good line of sight that, that's on target, as is our drilling pace for the year.
The midstream portion of our business right now, as far as -- in the Wattenberg, there's probably 2 pieces to talk about now. First is DCP.
DCP has done a good job, a fair job for us as we've gone through the year. We experienced higher-line pressures than last year by about 25 PSI in the last look I saw.
But overall, these have been modest increases, some of them were anticipated. And DCP is diligently working on, I believe, there's 4 major compressor station projects that are going to come online next year, one significant pipeline loop that will contribute to lower-line pressures in PDC area and the Lucerne 2-plant start-up, which is a 200-plus million a day plant.
So significant capital being spent by DCP, in line of sight of ongoing improvements in line pressure. So we feel good about where we're headed with DCP right now and feel pretty good about where we're at going through the winter months here.
The second component of our midstream is Aka Energy. We've recently initiated our first horizontal production to Aka on the Ram Land pad.
Again, that's a 7-well pad in the inner core. I believe we've got another Wiedeman pad that is scheduled to come online here in maybe the next month or 6 weeks.
It should be another significant producer. And we are extremely pleased with the performance, particularly in the Niobrara, of these inner core locations.
So we're seeing significant production, some of that natural gas. But very, very significant production from these inner core locations.
So Michael, hopefully, I covered everything there.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Yes, that's helpful, I was just trying to get a better feel in the context of 45 wells coming out, a lot of them in pretty, to your point, on high-productivity areas, [indiscernible] are the U.S. midstream plan.
Sounds like Aka's treating you well and DCP has been doing their part as well. And then, I guess, how many -- do you know how many wells were turned -- I'm sorry if missed it somewhere, but how many turned to sales in the third quarter and what are the plans in the fourth quarter from the Codell by chance?
Barton R. Brookman
Oh, boy, I don't have that -- those figures. I know totals, but I don't have the breakdown on Codell.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Fair enough. I'll circle back.
And then, I guess, last on my end, can you just remind me in terms of the choke management over in the Utica, as you march the other wells up, what's the kind of standard practice, and what sort of choke size do you think you -- ultimately marks these Palmer wells up to and over what time frame?
Barton R. Brookman
I think you can expect the choke management that we will maintain pressure on the wellbores, depress the IPs, expect very flat declines for a good portion of the early life of the well. And I don't think our teams when we are in the condensate portion plan on being over a 20/64s choke.
And I think they'll manage that depending on the completion style, slick job stages, lateral length, a lot of different factors. They really use the production in the pressures in the wellbore to manage that, but I don't see us in that portion of the phase behavior going above a 20/64s.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Okay. And just kind of slowly increasing profile -- or stable profile, roughly how long do you think that is maintained?
Barton R. Brookman
Yes, I think that's -- that the production profile for the year is going to be stair steps at lower IPs, but you won't have the front-end steep decline on the wells.
Operator
Our next question comes from Brian Corales of Howard Weil.
Brian M. Corales - Howard Weil Incorporated, Research Division
Just a few on the extended laterals. On the pad that you're testing, I guess, the 10 extended lateral wells, are you all experimenting with the different type of completion techniques there?
And can you just also remind us kind of drilling days and costs that you are [ph] for an extended lateral?
Barton R. Brookman
Yes, let me start with the last part. The extended laterals, particularly as we go the balance of this year and as we go into next year in our capital budgeting, a 6,500-foot extended lateral with the modified completion designs of 200-foot, expect $5.5 million to $6 million per well.
But step back to the 4,200-foot -- to 4,500-foot laterals, which will still be part of our capital program, that capital structure -- cost structure will be modified from the 4.2 we originally to more like 4.5 based on the increased stages we're executing on the lateral. And then your question around this year's 20 plus, just slightly over 20 extended reach laterals.
There's 2 things going on with those. First, we will be executing the 200-foot stage lengths on some of those.
So that is an absolute yes. The second thing is some of those laterals are also part of our downspace projects, the 20-well equivalent.
So we've got a blend of lateral length, stage length and downspace in some of these wells, which is going to be tremendous data for our team. It also can complicate things sometimes because you have to separate performance of one factor from another factor.
But overall, we're prepared to evaluate that and we think we're going to get tremendous data to report back to the market.
Brian M. Corales - Howard Weil Incorporated, Research Division
Okay, and just one more, can you maybe comment on the differentials and what you're seeing, if you see that improving in the next couple of quarters?
Barton R. Brookman
The differentials on which bay [ph]? You want...
Brian M. Corales - Howard Weil Incorporated, Research Division
I'm sorry, in the Niobrara.
Lance A. Lauck
Yes, Brian, it's Lance here, from a crude oil standpoint we're, for the quarter, around $12.50 on the D-deck [ph], and that's from wellhead all the way back, including all of the different feeds from marketing, et cetera. So about $12.50.
I think for the year, we talked about $12 per barrel on the differential and we think we're going to be fairly close to that. We're seeing some recent differentials that are being offered up that are definitely coming inside the $12 per barrel, so that's something that's very helpful.
And as you know, in April of next year, we've got commitments for 6,600 barrels a day of crude oil on White Cliffs pipeline that goes from Wattenberg down to Cushing. And that's around the $9.00 to $9.25 per barrel.
We look very favorable going into 2015. I think on the gas side, we're very pleased to see what CIG has been doing relative to NYMEX.
In the third quarter, it's $0.20, which is very favorable. There's been some shortness, if you will, of some gas supply headed to the Western United States.
So we have some benefits there from that differential. And then so for the full year, we'll probably estimate it to be about $0.25 on CIG.
Then as you go into next year, 2015, we're seeing about a $0.25, $0.23 to $0.25 on differential for CIG. So from that standpoint, the differentials look to be shaping up fairly favorable here going forward.
Operator
Our next question comes from David Tameron of Wells Fargo. Our next question comes from Mike Scialla of Stifel.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Bart, you said a couple of times you're extremely pleased with the inner core wells, can you put any numbers out there or at least, I think, you had had an estimate of 500,000 BOE per well, how are those wells performing versus that type curve?
Barton R. Brookman
Oh boy, and Mike, I don't have an answer on that. I know the initial rates in the pressures, particularly in the Niobrara.
The teams are really encouraged. Aka has had this Wiedeman Compressor Station, I'm getting into the weeds here a little bit, that has -- they're currently working on an expansion.
So we have basically maxed out their plants, I think, and this Wiedeman Compressor Station and we've got a lot of running room on these wells once they get the expansion up and running. So the wells are performing very well, pressure-wise and rate-wise, I think we may be close to type curve right now.
And we've got more to go on the pad. So we're working together with Aka to get -- and that Wiedeman Compressor expansion is scheduled to come up here in the next week, I believe.
So again, we're just overall -- it's very early here. I mean, we've got several weeks of production on these pads.
And -- but I can just tell you, in the Niobrara in particular, we're just seeing very, very strong production.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
How about when you look at that inventory of 90 locations? I know you guys are doing a lot of testing as everybody else is on spacing here.
There's a lot of vertical wells in the inner core, should we think about in terms of the upside potential for increased density drilling, is it maybe not as great in the inner core because of the vertical wells? Or I guess, based on some other of your competitors drilling in that area, do you think there is a chance to increase the density and maybe boost that inventory of 90 locations?
Barton R. Brookman
I think there's a significant probability that we would increase it in the Niobrara, and I think we're steady-state in the Codell right now. We continue to manage the Codell wells, they're performing extremely well overall, in line with our type curve.
But we, absolutely in the Codell, do see some impacts, particularly when we're fracking from those original vertical Codell wells. The Niobrara, not so much.
We're just -- it's more of a steady-state performance on it. So the upside in the inner core, in the more inner portion of the middle, I think production and reserve-wise will come from the Niobrara.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Okay. And switching over to the Utica, managing the choke size there, when would you expect to see -- or I guess, what are you modeling in terms of a decline where your -- or an increase in your GOR over time, how long can you hold that, do you think, at a 70% liquids rate?
Barton R. Brookman
I think we'll see some modest increases in GOR overtime. I don't think we're going to see any -- the way we're managing, I would call it dramatic spikes.
The decline is probably the question of the day for our operating team. And we've had a lot of debates around with these longer laterals, how long do you hold flat pressures and how long do you hold flat declines because the inflow performance on the well is a combination of the lateral length and the reservoir we're contacting in the choke management at the surface.
So as we go longer laterals and change our completions, we're optimistic that we're going to be keeping this flat production profile with say, on a 18 choke, for a much longer period of time. So Mike, when that decline starts kicking in a little more aggressive is kind of the million-dollar question.
But we're going to have to be patient. We need time to evaluate that.
It's very, very difficult from a reservoir simulation to model.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Got you, okay. And then last one for me, maybe I was reading too much into it, but sounds like you're anticipating production earlier from that Dynamite pad than I had thought.
Is that -- are you still doing the resting period? Is that kind of been -- have you taken that off the table now?
Barton R. Brookman
Yes, the resting period is more like 30 days right now. And we'll continue that on the -- I think we'll probably be wrapping up the Dynamite completions here next week.
And as I noted, 163 stages across 4 wellbores that our team has executed on the last, I think, probably a month we've been on that project. So outstanding performance there by our completion group.
But yes, I think the mid-December is in line with our modeling. And to the earlier question about the number of turn-on-lines in the fourth quarter, that's obviously one of the pads -- 4 wells, but that's part of the forecast.
Operator
I'm not showing any further questions. I'd like to turn the call back over to Mr.
Trimble for any further remarks.
James M. Trimble
Well, thank you, operator. I'd just like to say thanks to everyone for joining us today.
And that's it. Thanks.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program.
You may all disconnect. Everyone, have a great day.