Aug 1, 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
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Welles W.
Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division Irene O. Haas - Wunderlich Securities Inc., Research Division Ipsit Mohanty - Canaccord Genuity, Research Division Michael S.
Scialla - Stifel, Nicolaus & Co., Inc., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division Raymond J.
Deacon - Brean Capital LLC, Research Division David E. Beard - Iberia Capital Partners, Research Division
Operator
Greetings, and welcome to the PDC Energy 2013 Second Quarter Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.
On the call today is Mr. James Trimble, Chief Executive Officer and President of PDC Energy.
Joining Mr. Trimble on the call 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, Mr.
James Trimble. Mr.
Trimble, you may begin.
James M. Trimble
Thank you, Kevin. Good morning, everyone, and thank you for joining us today to discuss PDC's second quarter 2013 results.
As the operator mentioned, on the call with me today are Gysle Shellum, our CFO; Bart Brookman, COO; and also Lance Lauck, Senior Vice President, Corporate Development. We posted slides of our webcast today and let me begin by drawing your attention to our Safe Harbor language as it relates to our forward-looking statements and projections in today's presentation.
I will discuss highlights for the quarter followed by additional details from Gysle in the financials and then Bart on the operations. We had a very solid second quarter for 2013 with net income of $20 million and production levels meeting our guidance.
Our production forecast, with its midstream Wattenberg constraints, proved accurate in the quarter. Yet we still outpaced production in the second quarter of 2012 by 34%, with crude oil up 40% and NGLs up 44%.
The year-over-year growth was driven primarily by the Wattenberg field, which includes the continued success in our horizontal drilling program and the Wattenberg assets we acquired in the third quarter of 2012. We also grew our Marcellus production year-over-year.
We closed the sale of our non-core Colorado assets in mid-June, which not only provided gross proceeds of approximately $200 million, but was also a major achievement in our stated strategy to position the company to grow above liquid production and percent liquids in addition to our cash margin. Company-wide, our liquid mix from continuing operations was 54%.
The Wattenberg Field continued to be the source of the vast majority of our liquids, over 98%. But we expect to have Utica liquids contributing more significant in the third and fourth quarter of 2013.
We expect to see natural gas volumes from our Marcellus increasing, beginning in the third quarter as we bring a 4-well pad online this week and within the next month, complete a 3-well pad in terms of sales. The financial impact of the higher liquid mix has had our cash margins, which is in G&A and production cost from continued operations or approximately $28 per Boe and in the second quarter.
That is nearly double the full year average in 2012's $16 per Boe. As I mentioned, we had net income for the second quarter of $20 million or $0.64 per diluted share.
Net income from continuing operations was $17 million or $0.53 per diluted share. Adjusted cash flow from operations increased 57% from the second quarter of 2012 to $46 million, while it increased 25% to $98.7 million for the 6 months ending June 30, 2013 compared to the same period at 2012.
Bart will give you an update on operations, but I want to emphasize that we're very pleased with our continued success in both the horizontal Niobrara and Codell drilling programs in the Wattenberg Field. Our drilling of the Waste Management section began in May with 2 rigs, one of which was our third horizontal rig into the field.
We will drill a total of 16 horizontal wells in the 640-acre section and are currently drilling our 12th well. We are targeting the Niobrara B with 6 horizontals, the Niobrara C with 4 and Codell with 6.
This section represents our tightest operational horizontal downspacing to date and will provide us with valuable data to value both spacing within benches as well as potential spacing between the different benches or zones. In the Utica play in Southeast Ohio, we are finishing our eighth horizontal well, which is the second well in the Detweiler 3-well pad in Guernsey County.
You may recall that we drilled an IP in the first Detweiler well around the beginning of the year. That first Detweiler well was tied into MarkWest system in late July and is now in full production.
The second well, the Onega, was tied into MarkWest system last week and is now on production as well. We completed drilling 2 horizontal wells in Southern Utica acreage, in Washington County.
We're encouraged by the geological data from those wells and expect to complete them in August. We'll rest them for 30 to 60 days and anticipate initial production around October 1.
Those wells will be tied into the Blue Racer high-pressure system. We just completed frac-ing all 3 wells on the Stiers pad and after resting period and expect to test the first Stiers well into a low-pressure system in mid-August.
The other 2 wells will follow after their rest period in September. At present, we have 5 horizontal rigs drilling, 3 in the Niobrara play, 1 in the Utica play and 1 in the Marcellus.
We extended the maturity date of a revolving credit facility to 2018 along with confirming our borrowing base post closing of a non-core asset sale of $450 million. After closing the sale of the non-core Colorado gas assets in June, we're currently undrawn on our revolver with approximately $43 million in cash as of June 30.
As of the same date, we have $479 million of available liquidity on a consolidated basis. In summary, PDC had a very good first half of the year with solid results from our Wattenberg operations.
As we forecasted, we expect production to grow from all 3 basins in the second half of the year. We continue to focus on adding value to our shareholders and are in excellent position with our hedge portfolio and ample liquidity to continue to execute our 2013 capital program and business plan.
I will now turn the call over to Gysle for his financial review of the second quarter.
Gysle R. Shellum
Thanks, Jim, and good morning, everyone. As usual, my comments will be high-level for the quarter, so for a more complete analysis of our quarterly and year-to-date results, please refer to our press release and 10-Q that we filed this morning.
Overall, our second quarter and year-to-date financial results are in the midrange of our guidance that we provided in April if you adjust for the noncash impairment in the first quarter that we took related to shallow production assets in Marcellus. Based on our results through June 30, we're reaffirming our full year guidance.
Let's take a look at some of the key financial results. Total sales on Slide 6 are from continuing operations and exclude realized hedging gains and losses for the quarter.
Results from continuing operations in all periods exclude operating results from Piceance in our Northeast Colorado field, including in the non-core asset sale that closed mid-June. Comparable results for 2012 also excluded Permian Basin operations that were sold in February of 2012.
Wellhead oil -- wellhead prices for oil were relatively flat in the second quarter this year, averaging $87.32 compared to $87.90 since last year. However, gas prices at the wellhead improved significantly to $3.79 in the current quarter compared to $2.05 last year, an 85% increase.
NGLs made up 17% of our current quarter production on a Boe basis, but contributed only 8% of oil and gas sales compared to 16% of production and 10% of sales in the second quarter last year. Price declines led by the heavy components were the cause of the drop in revenue contribution.
Average price per NGL barrel fell to $23.55 in the current quarter and $26.65 in the second quarter last year. Things have gotten a little better in July for NGL prices.
So hopefully it's hit bottom, but prices are still very low for NGLs and we don't see meaningful near-term help. Overall, for the quarter, our weighted average wellhead price increases to $47.10 per Boe, a 13% improvement over the second quarter 2012.
Increased production drove a 51% increase in oil and gas sales to $77.5 million in the current quarter compared to $51.3 million in the same quarter of 2012. Year-to-date sales increased 33% to $157 million from $118.3 million in 2012.
Production cost from continuing operations for the current quarter were $16.2 million or $9.83 per barrel of oil equivalent compared to $12.4 million or $10.06 per barrel of oil equivalent in 2012. Per unit decline is a result of increased production.
Gross margins on sales, less production cost from continuing operations, excluding realized gains and losses from hedges in each period, resulted in the $61.3 million of gross margin in the current quarter were $37.27 per barrel of oil equivalent compared to $38.9 million or about $31.67 in the second quarter of 2012. The increase in the per Boe gross margin followed the increase in the weighted average price at the wellhead that I just mentioned.
Bart has more detail on the margins later. Adjusted cash flow and adjusted EBITDA include results from discontinued operations.
Both metrics also include net realized hedge gains of $3.9 million before taxes in the second quarter this year compared to $16.2 million in the second quarter of 2012. Unrealized hedge gains and losses are excluded from both adjusted EBITDA and adjusted cash flow.
These are non-GAAP measures that we reconcile to GAAP in the appendix of this presentation and in this morning's press release. Adjusted cash flow from all operations increased $16.9 million compared to the second quarter last year.
Year-to-date adjusted cash flow increased $19.5 million over last year to date. Adjusted EBITDA in the current quarter increased $12.6 million compared to the second quarter last year.
Year-to-date, adjusted EBITDA for 2013 includes a small loss in sale of assets of about $1.1 million and year-to-date adjusted EBITDA for 2012 includes total gains on sale of assets of about $22.3 million. So if you adjust for the impact from the sale of properties or the gain or loss on sale on properties in both periods and compare adjusted EBITDA only from oil and gas operations, current year-to-date adjusted EBITDA would show an increase of about $20 million over year-to-date last year.
Year-to-date adjusted EBITDA per diluted share also reflects the gain and losses from sale of properties in each period that I just mentioned. Excluding these events, year-to-date adjusted EBITDA per diluted share in 2013 is $3.84 on 30.3 million shares compared to $3.75 per diluted share based on 25.3 million shares in 2012.
Moving to DD&A. DD&A from continuing operations increased slightly during the current quarter compared to second quarter last year.
The increase is a result of increased production during the quarter. Same is true for year-to-date comparison.
Our DD&A rate has decreased compared to last year as a result of the increase in reserves, primarily in Wattenberg, and also as the result of the first quarter impairment on our shallow Appalachian properties that we classified as held for sale. Our DD&A from producing properties from 3 to 6 months ended June 30 is about $16.10 per Boe and for the same period last year, it was about $18.25.
Same holds true for G&A. Our cost per Boe produced is decreasing as production ramps up and we expect this trend to continue.
On Slide 7, the top half of this page is net results from operations attributable to shareholders per GAAP, which includes realized gains and losses from mark-to-market hedge positions as well as discontinued operations. We recorded after-tax net realized hedge gains of about $12.9 million in the second quarter 2013 compared to after-tax net unrealized hedge gains in the second quarter of 2012 of about $13.9 million.
The bottom half of the page shows adjusted net income and earnings per share with unrealized hedge gains and losses removed. There's a reconciliation of these schedules in the appendix of this presentation.
Adjusted net income and loss numbers include both gains and losses on property sales as well as impairments. I mentioned in our earnings call last quarter that we had stuck to this formula to be consistent in the way we present these numbers.
The impact of property sales is insignificant in the current quarter's comparison. Year-to-date, 2013 includes the impairment of about $28 million after-tax that was recorded in the first quarter.
Year-to-date 2012 includes the after-tax gain of about $13 million related to the sale of properties in the first quarter 2012. Year-to-date adjusted net income from all operations before the impairment and the gain on sale of properties would be approximately $35 million or about $1.16 per share for 2013 and approximately $200,000 or about $0.01 per share for 2012.
As Jim mentioned, we closed the sale of our non-core gas assets in June. This debt schedule reflects PDC's revolver excluding our share of $36 million of nonrecourse debt in our joint venture that is consolidated in our financial statements.
After adjusting for the January 1 affected date and other closing items, we received proceeds of about $173.3 million as of June 30 from the sale. Proceeds paid all of our outstanding security indebtedness with only $19 million letter of credit left outstanding and left us with $43 million cash on hand.
Subsequent to June 30, we received an additional $9.2 million in cash from our sale of partner -- from our share of partnerships and sold properties in the same transaction. There are still some small post closing adjustment that will be settled in Q3 related to the sale but they won't have a significant impact on the liquidity of $474 million in cash and available credit shown here.
We expect we'll begin drawing on our revolver again late in the third quarter, beginning in the fourth quarter. We also executed an amendment to our credit agreement during the second quarter that Jim mentioned and extended the maturity to 2018 as shown on the graph.
This sets us up to execute on our development plan with plenty of liquidity and a strong balance sheet. A quick update on our bonds.
Our $500 million of 7.75% high yield bonds were placed privately last year with registration rights. The filing to register these bonds was effective July 9 and the exchange to registered securities is currently underway.
This last slide looks at our hedge positions as of June 30, 2013. Not much is changed here from the first quarter presentation except for the expiration of our second quarter hedges.
WTI began its run in early July and the impact was mostly in the front of the curve where we are already fully hedged. The oil curve did move up a little in the back end in July and we locked in some oil hedges that included some production in the last few months of 2014 through year end 2015.
Prices on these swaps averaged in the high 80s and those hedges were executed in July, so they'll show up in the third quarter presentation. We also added some gas hedges in July for production in 2015 to the middle of 2016, using cost as collars with $4 floors and $4.50 ceilings.
Now, we're about halfway through our 2015 program and working on adding hedges for the remainder of the year. As you know, we aggressively hedge our production to protect our cash flow and our capital program.
With that, I'll turn this over to Bart for comments on operations for the quarter.
Barton R. Brookman
Thank you, Gysle. And hello, everyone.
And once again, strong quarter for our operations team. As Jim and Gysle noted, production improved 34% from prior year levels for the second quarter, but we couldn't be more excited about where we're at as we have tremendous opportunities to grow production as we go to the second half of 2013.
Let me just hit some highlights on the map here. In Wattenberg, despite the ongoing high line pressures, our Wattenberg production grew 40% from prior year levels.
In the Utica, we were pleased to have our first real sustained production from the Detweiler well and our Marcellus production was right in line with our expectations. The cumbersome production highlights for the company is shown in the bar graph.
Production for the quarter was right in line with our guidance at 18,100 barrels of oil equivalent per day. The company's production mix was 37% oil, 17% NGLs and 46% natural gas or a 54% liquid mix.
Through the end of June, we were 2% above our guidance levels. In the Wattenberg Field as Jim noted, we did deploy our third rig at the end of May.
This rig will begin contributing to production in the third quarter. We are currently on the 12th of 16 wells on our Waste Management pad, this is our down-spacing project, and DCP's LaSalle plant is on schedule for startup October 1.
In the Marcellus, our 4-well D'Annunzio pad is scheduled for first sales this week. We are currently completing the Goff 3-well pad in Harrison County and should have first sales on this project in September, and we are currently drilling on the O.E.S pad in Taylor County, this is a 3-well delineation test for us.
And then in the Utica, our Detweiler 42-3H well, which we announced last quarter at 2,200 barrels of oil equivalent per day initial test was turned to sales for the bulk of the second quarter. It had a first 7 day average of 1,700 barrels of oil equivalent per day and a the first 90 day average of 700 barrels of oil equivalent per day.
Both these rates are approximately 75% liquid mix. Currently, our reserve group projects this well will land somewhere between our 2 type curves of 500,000 barrels and 750,000 barrels equivalent.
We should note, this is a 3,800 foot lateral where we had executed 13 stages in the completion and our current operating practice has quickly migrated to 5,000 to 6,000-foot laterals in this play and we're executing 20 to 30 stages per lateral. I should also note that for the quarter, that this Detweiler well was into a temporary midstream solution, so we had some more intermittent type flow on.
And as Jim noted, recently, we turned this well into MarkWest, which is our long-term, more reliable midstream solution. Let me quickly refresh everyone's memory on the map we presented at analyst day that defines our 3 areas which we used to show well performance and book reserves within our core Wattenberg, horizontal Niobrara program.
Again, these 3 areas are the outer core, the middle core and the inner core. Let me update everyone on the Niobrara program.
We are enhancing our performance presentations to represent additional data within the 3 areas. Again, the outer, middle and inner core.
This is to provide more clarity on the Niobrara's production and reserve performance and the liquid percentage within each of the 3 areas. And this will directly align with our year end booking process.
For each area, we're giving a performance range, which is in light gray on the plots, and an average type curve for production and reserve performance. I should note these type curves were developed using over 300 wells and we did include the cleanup period that we are seeing in the first 60 to 100 days of the well.
Statistically, this should provide better definition of our drilling opportunities and as an outstanding indicator of the quality and the distribution of the company's inventory within the core Wattenberg Field. Besides reserves for each area, we have given you estimated IRRs, PV10s and our current inventory, which you can see the majority falls within the middle core area.
Overall, our Niobrara program continues to deliver outstanding results, which we anticipate will improve as we go through 2014, as we migrate our drilling programs closer to the inner core area. Next, let me give a quick update on our horizontal Codell program.
This program, again, continues to deliver outstanding results for our Wattenberg operating team. We are happy to announce we have 15 wells to report in our average and are comfortable presenting our first type curve for Codell performance.
You can see 345,000 barrels of oil equivalent. The shape of the curve, it does exhibit a flatter decline profile than the Niobrara.
Approximately 80% returns on our drilling and a PV10 per well of over $5 million. Again, outstanding results are currently being delivered by this Codell drilling.
I should note, the bulk of these 15 wells presented here are in the northern part of the field and reserves overall should improve as we migrate this drilling program towards the more inner portion of the Wattenberg Field. Also, as we develop more data on the Codell, we will move to a presentation format similar to what I just covered in the Niobrara where we break out performance by area.
A quick update on the Wattenberg midstream expansions. I'm very happy to announce that DCP is on target for the LaSalle plant startup on October 1.
We've provided some details on what you can expect over the next several months. Let me just hit some of the highlights.
First, the LaSalle Plant will be mechanically completed by the end of August. Also in August, all field compression will be completed that is necessary to accommodate high-pressure deliveries to the LaSalle Plant.
In September, expected initial phase of the FREX NGL line to be of service from the LaSalle to the DCP Mewbourn plant and provide delivery to OPPL. And then on October 1, La Salle should be in service.
At that time, we should see improved line pressures across the field in particular, the northern part of the Wattenberg. And then in 2014, we expect the FREX NGL line will be fully in service and provide NGL markets to Mont Belvieu.
A little more detail on our Utica drilling. On this map, the brown boxes are the wells, which we have finished drilling.
You can see our Onega and Detweiler wells to the north. Those are the wells we have announced initial IPs.
Just south of those is our Stiers 3-well pad. It is drilled and completed and is currently in resting mode.
We will have first sales on this sometime in September. The Garvin and Neill wells, our first wells in Washington County, should have first sales sometime late September, early October.
And in the turquoise boxes, these are the wells yet to be drilled this year. Overall, we are on target for 11 wells to be drilled in 2013.
Currently, we are drilling our sixth well for the year and we anticipate we'll have first sales on 9 wells by year end 2013. An overview of the company's drilling program for the first six months of the year.
39 operated wells were drilled through the end of June, 27 in Wattenberg, 5 in Utica, 7 in the Marcellus. We also participated in 18 non-operated projects in the Wattenberg at an average working interest of 20%, giving us a total number of drilling projects we participated in of 57.
The company is on target in 2013 for 131 wells to be spud, 95 of those operated, 36 non-operated. On the refrac and recomplete projects, we have only executed 6 year-to-date, well behind our plan of 48.
We will not execute any additional re-frac or re-completes until we see noticeable improvements in line pressure in the Wattenberg Field. Current drilling activity for the company, as Jim covered, 3 rigs in the -- horizontal rigs in the Wattenberg, 1 horizontal rig in the Utica and 1 horizontal rig in the Marcellus.
An update on our capital program. For the quarter, we spent $79 million, right on target with plan, $59 million of that in Wattenberg, $17 million in the Utica and $3 million on miscellaneous and leasehold projects.
Overall, we are on target for the year for our $387 million improved budget. Again, the bulk of that will be in the Wattenberg field.
Within the PDC Mountaineer JV, $16 million was spent for the quarter on our 1-rig drilling program. We are on target within the Mountaineer division for the total of $57 million.
And again, that is PDC's 50% share within the JV. A quick overview of operating cost.
Lifting costs were up slightly for the quarter to $4.97 per Boe. Nothing to worry about here, this was an increase of some slight increases in our labor costs, but also some onetime catch-up on some jibs for non-operated properties.
For the year, we still anticipate being on our guidance of $4.88 per Boe. Expect improvement in our lifting costs in the fourth quarter when we will see strong increases in our overall corporate production.
A new presentation on the right, gross margin for the quarter was $37.27 per barrel equivalent. Our production for the company is delivering very strong margins with our high liquid mix and you can see the breakout of how we got to this bottom line margin with our sales at $47.10 per barrel equivalent net of our LOE and our lifting cost overhead and production tax to get to the gross margin of approximately $37.
So highlights. In Wattenberg, quarterly production in this basin was 15,000 barrels equivalent per day, 6,000 of that was from our horizontal programs.
Right now, our horizontal program is contributing 40% of the production in this basin. In the quarter, we drilled 10 Niobraras, 6 horizontal Codells.
Again, our Codell program continues to shine. Our D&C costs remain at $4.2 million per well, both in the Niobrara and the Codell and our Waste Management project is nearly complete on the drilling side.
Completion should start over the next month, and we should have first sales within the next couple of months. Line pressure relief is just around the bend.
Hopefully, about 2 months from today, we should see some dramatically improving line pressures in the Wattenberg field. And then the Utica, we have our 46,000 acres.
Most of the acreage, we're very pleased, was in the liquid-rich window. Currently, we're drilling the Detweiler 2H.
This is a 6,000-foot lateral, just offsetting the Detweiler I talked about. Our Stiers 3-well pad is completed, currently resting and we're waiting on first sales here.
The Garvin completion, I'm happy to announce, is underway as we speak. The Neill completion is scheduled in a couple of weeks.
9 wells will be online by the end of the year and we initiated sales in the MarkWest and Guernsey County in late July. And then Marcellus, we've got 4 long lateral wells coming online this week.
We're currently completing the Goff pad, that should be online in approximately a month. And we're currently drilling the O.E.S pad, which will be online hopefully, in about 2 to 3 months.
With that, I'll turn this back to the operator for Q&A session.
Operator
[Operator Instructions] Our first question comes from Ryan Oatman with SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Bart, can you talk about how rested these Stiers pad wells and whether you plan any modification to your Utica resting period based on what you or others have found, whether it's 30, 45, 60 days?
Barton R. Brookman
Yes, and we are, on a general technical perspective, targeting the 45-day period right now. But on the Stiers in particular, we have tried 1 surfactant that we think is going to enhance the imbibing period.
So we'll have one on that well, a 30-day rest. On a second well in the Stiers pad, a 45-day rest and on the third well will be a 60-day rest.
So we are going to try some different things here, including 1 surfactant that we're excited about.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay, very good. And I've heard you correctly in the south that the Garvin is completing now, the Neill in a few weeks.
Do you anticipate that you'll have those wells available given similar sort of resting periods, I guess, a little bit later in the third quarter?
Barton R. Brookman
Yes. Again, I haven't seen the final recommendation from the operating team on both those wells, but I would anticipate they're going to be in the 45 to 60-day period.
Unless we bring this Garvin on -- or I'm sorry, Stiers on in the 30 day, has an exceptional performance.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
And in on this Detweiler well, I know you tested it for a while, selling condensate before getting it into a line and a temporary one at that. Do you think any of that impacted your test rates at all, and the potential for your upward or downward movement once you kind of have a more regular sell into a permanent line type situation?
Barton R. Brookman
Yes, absolutely. We were testing into a temporary midstream pipeline.
We were also operating our own small processing facility. So all of that brought, I would classify, as additional complications on the production side.
As we noted at the end of July, the well went to MarkWest and we are already seeing an enhanced production on the well from the time it went into MarkWest. So it definitely will help us.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Can you quantify that or you don't care to at this time?
Barton R. Brookman
Not right now because we're still combining a lot of things out.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay. With LaSalle Plant in service October 1, it sounds like you guys have already kind of prepared for a little bit of delay in the start up.
Does that change your production expectations at all? And then kind of a similar question with the Senica plant in Utica, any updates there versus your expectations?
Barton R. Brookman
No, it does not change our production guidance for the Wattenberg Field or for the company. And I believe we modeled -- when we put our guidance together for the Wattenberg, we modeled the LaSalle Plant benefiting our production beginning October 1.
So it just so happens the actual plant startup is right in line with what we modeled. So we feel pretty good about the engineering there.
And then on the Utica side, the MarkWest, we're currently going the Cadiz plant. The Senica plant, I think, is a couple months off from startup.
So based on everything we know in communications with MarkWest, we're covered on gathering and processing capacity in that basin.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay, and then one final one for me here. Just seeking to simplify the Niobrara information presented, how do these estimates compare to what you've laid out before, broadly speaking?
And then how would you rate kind of those returns versus Utica and what would you need to see to add another rig in the Utica?
Barton R. Brookman
The presentation I gave is right in line with what we've presented prior, it's just dissected into 3 parts. So we're just trying to provide more clarity to you guys as we move these rigs around the field, in particular, as we migrate from kind of the outer of that middle and the inner of the outer, if that makes sense.
And we're migrating more towards the heart of the core Wattenberg as soon as LaSalle comes online. And the second part of your question was on the Utica as far as guidance?
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Just how you would compare, say, these IRRs that you're seeing in the Wattenberg versus the Utica and what would encourage you to add maybe a second rig over in the Utica at some point?
Barton R. Brookman
Well, we haven't finished our budgeting process yet. And in the Utica right now, as I said, our first well, we think is coming in between the 500,000, 750,000-barrel.
We're very encouraged. It's our swing at the ball and we're pleased with the returns we think we're going to achieve on that well.
We're at about $9 million of wells still in the Utica. But overall, I guess, Ryan, to really answer that question, we have to get a handful -- additional handful of wells online and really evaluate.
But based on what we know, we think we're going to have a good challenging allocation of capital decision coming here when we put our budget together in the November timeframe.
Operator
Our next question comes from Leo Mariani with RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
On what the Garvin and peer [ph] -- and Garvin wells look like at this point and the Neill well?
Barton R. Brookman
All of the technical data that we have gathered from logs, our geological control and our drilling data including shows, I would classify as very encouraging.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay, that's helpful. I guess just additionally, I'm looking at your Wattenberg production for the last couple of quarters.
I mean, it looks like 2Q versus 1Q, the oil came down a fair bit but your NGL went up and your gas is kind of flattish. How should we expect that to play out in the second quarter or the third quarter?
Are we still going to see oil volumes somewhat repressed and then they jump a lot in the fourth quarter? Just any kind of commentary you have on your hydrocarbon mix over the next few quarters as this LaSalle Plant comes online?
Barton R. Brookman
Leo, I would stick with our guidance. The second quarter, we -- the last 2 weeks of June, and this was not sustained probes [ph] on DC parts, these were temporary onetime events, but we had 2 significant downtimes.
So some of what you saw on the liquid side was a wound where we actually had some wells in the northern part of the field shut in. So, so far, this quarter, we've had pretty good run times.
DCP is doing a good job with their bypass. It hasn't been overly hot in the Wattenberg Field or in Colorado.
So we've had pretty good run times. So the best I can do is to say I would go with the guidance.
Operator
Our next question comes from Welles Fitzpatrick with Johnson Rice.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
In the Utica up north, any lease line issues on the long -- I think you said 6,000-foot laterals?
Barton R. Brookman
No. We've got our drilling program right now laid out within our current acreage but Welles, that isn't stopping us from going out and trying to a, acquire some bolt-on acreage, which we've announced is part of our Utica budget.
I'm sure we can achieve those longer laterals or the concept of trying to pull some other operators in.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
And on the -- now that you guys have a little bit longer rates up there, anything to change your mind on I believe, the analyst day was the last time you updated on the EURs up there. I think it's 500,000 to 750,000.
Barton R. Brookman
No. I would say based on the data we have right now, we don't have enough to change our perspective on that.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
And one last one. On the Stiers pad, the completion itself, can you describe as that will go off without a hitch, all the stages were put away fine or did you have any issues there?
Barton R. Brookman
No issues. We executed I think, an average of 22 or 23 stages per well.
Our average spacing, we have taken down to about 200-foot per stage or just slightly over 200. And I would classify the completion execution as exceptional by our operating team.
Operator
Our next question comes from Irene Haas with Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
I just kind of want to focus on the Codell. Obviously, you have a whole lot more wells and a longer production history and it looks like at least for the northern part of the basin, you seem have kind of backed away from your 500 million -- I mean, 500,000 barrel per well EUR.
Just kind of want to have a little color as we kind of go forward as you drill more wells, could we expect sort of an update and how would this eventually shake out? That's the question.
The second one has to do with Utica. Kind of adjusting for the 5,000-foot lateral, should we be expecting sort of EUR towards the million barrel range for your Utica wells?
Barton R. Brookman
Okay, in the first part, Irene, let me clarify. I don't think we've ever been on record saying that the Codell program was going to be 500,000 barrels.
We had a plus where we had 1 well in particular that is still our 4th best performing well in the Wattenberg Field that was really doing the overall performance of the Codell curve. But I think we only had 4 or 5 wells in that curve.
And we -- I think we have always told the market, as we add more wells, expect that curve to come down. So we feel very good about the 345,000 and probably what we feel even more encouraged by is that is on the outer fringes, the 345,000 is a tight curve we feel comfortable presenting to the market and we do have some confidence that as we go more towards the core that, that Codell performance probably will improve.
So hopefully, I answered your question on the Codell. On the Utica, I would say this.
I think right now with the limited data we have in-house, we would stick with the 500,000 and 750,000. I would say if anything, based on some of the data we have right now, with longer laterals and enhanced completions, I would hope our operating team have pushed our performance towards the upper end of our type curve range.
Am I willing to jump out and say 1 million barrels? No.
Not yet until we get more data.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Okay, if I may follow up with one more question. How much are you getting for your condensate right now in Ohio and how's the market looking?
Local demand still pretty robust?
Lance A. Lauck
Irene, this is Lance. So for the condensates in Utica, we're getting approximately NIMEX minus $5 per barrel.
I would classify the market there as strong for condensate as there's multiple uses for condensate within locally as well as transportation up to Canada for dealing with there.
Operator
Our next question comes from Ipsit Mohanty with Cannacord.
Ipsit Mohanty - Canaccord Genuity, Research Division
Just taking a step back and it looks like as if your production is heavily skewed towards the fourth quarter. But if you can talk about the third quarter, I'm curious to see that your liquids stays flat as per the presentation, and your 1 rig drilling outside the Waste Management.
So whatever declines you see, are they exactly being -- will they be filled up by your incremental production coming in the -- from that lone rig outside the Waste Management? Could you give some color on that?
Barton R. Brookman
Yes, and I think when you look at the liquids for the quarter, the dynamic that probably is happening is we are drilling on the Waste Management pad in our models, did not have completions on that pad. So we've got our drilling activity without completions and initial rates in the Wattenberg.
So the liquid production in the Wattenberg is probably sustained or maybe even declining a little bit while we drill out this Waste Management pad. That's being offset in our model by some Utica production that is coming on tapered through the quarter.
I think that's the general trend of what you see going on with liquids. The gas side, you see a slight enhancement and that is primarily the company adding the Marcellus volumes, which as everyone knows, are dry gas.
So that's kind of the dynamic within the model and our guidance. And as I said to Leo, I think the best way, based on what we know right now, is to stick overall with our guidance in the third and fourth quarters.
Ipsit Mohanty - Canaccord Genuity, Research Division
Just again, more of a big picture question in the Utica. A number of operators, early stage of the play, each looking at others for sort of data and derisking.
A couple of the operators have talked about how they're doing a different kind science. If I put it broadly in the Utica completion techniques.
I wonder if you could -- if you're ready to share something in terms of what you're doing within those wells to kind of maximize production and EURs please?
Barton R. Brookman
Well, from a completion side, I think I gave a little flavor on that on the Stiers pad. I mean, our big motion or changes have been long -- first, longer laterals, the second is the team has really tightened the footage per stage down.
There's a very strong trend on that in this place. So we're down again, targeting about 200-foot of frac-ed interval per stage.
We're still learning a lot, we had a question about the cure period. It is something that we think is enhancing performance.
We're still trying to fully understand that but it is part of our operations and we'll continue to refine the flow back in the curing process. And probably, the next thing is, without going into a lot of detail, proppants and surfactants.
I mean, I think both of those are going to be big things based on the rock stresses we see and this whole curing, imbibing the fluids process that we go through. And our team has a lot of ideas on this and we're doing a lot of testing.
And I think over the next 6 months, it's going to continue to help us work up the learning curve on the completion side. And then the last thing is on the Stiers pad, we did execute microseismic and I can't -- without giving a lot of detail, it was a tremendous educational tool for us on what is going on within the completions in the Utica.
So hopefully, that answered your question. There's a lot of things we're doing.
And as Jim told me before the call, we're spending a lot of money on the science here. We've got $9 million a well, good chunk of that is dedicated towards science and the company continues to support executing on that science as we learn about the play.
Ipsit Mohanty - Canaccord Genuity, Research Division
But for every answer you said without giving details, so when do we expect any details?
Barton R. Brookman
By the end of the year, I would think.
Ipsit Mohanty - Canaccord Genuity, Research Division
And my final one. NGL pricing was weak and as you alluded to, just sort of when do you expect the NGL dilution from the Wattenberg to improve?
And is it a question of oversupply given the production ramp-up there overall by everybody and when do you expect some release?
Lance A. Lauck
Yes. This is Lance.
Our price per NGL barrel in Wattenberg was lower for the second quarter, primarily driven by oversupply of ethane and we experience that primarily in the months of May and June. Also, as you get more into the summer season, the demand for propane comes down a bit too.
It's more highly used during the winters period there. So the analyst day, we talked about guidance for the year as far as overall the prices for NGL as a percent of NYMEX, and we're around 33% there.
Based upon some of the recent weakness that we've seen, perhaps we're sort of in the 30% range as a percent of NYMEX, 30% to 33% for the year. And so that's sort of where we see it at this point in time.
As Gysle talked about during his comments, we do see a lot of continued pressure on NGLs for the foreseeable future.
Ipsit Mohanty - Canaccord Genuity, Research Division
And how far out do you think? Like, when do you think -- do you think 1Q '14 when the FREX pipeline comes into Mont Belvieu.
Barton R. Brookman
So we do believe that we will see some improvements with the FREX pipeline coming into place there. So we'll continue to monitor that and see how that comes about.
So we'll continue to see that because that gives access down to the Mont Belvieu markets there.
Operator
Our next question comes from Mark Scialla with Stifel.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
On the Detweiler, the 75% liquids that you mentioned, how much of that is condensate?
Barton R. Brookman
Mike, I don't have -- I'd go back to the press release in the first quarter. I think we broke that out.
It hasn't changed that much. I think it's about 50% condensate, the balance NGLs and -- 50% condensate, 25% NGL and 25% natural gas.
Lance A. Lauck
That NGL, Mike, would be a C2 plus. So the ethane plus extracted from the gas for 25%.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay. I guess what I was trying to get out was that has that changed at all from the IP river segue [ph]?
If it has not, it's held pretty steady.
Barton R. Brookman
There's, I would classify, a modest shift in the GOR. We're still evaluating that from a PVT standpoint and reservoir characteristics but it hasn't dramatically changed.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
Okay, and second Detweiler well, in terms of geology there look any different than the first or would you expect an improvement with the, I guess, longer lateral and more frac stages?
Barton R. Brookman
Yes, we expect enhanced performance.
Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division
And on the -- shifting over to the Niobrara, any update on the ride away pad? Still no signs of interference there between the 3 Niobrara benches and the Codell that you tested?
Barton R. Brookman
I haven't looked at that specifically in detail in the last 6 weeks, but no. I think the general feedback from the operating team is that we are not seeing any production interference between our tighter space laterals.
And I think the general trend in the industry as spacing's getting tighter and tighter, is that we're still searching for the optimum spacing where we can drill, optimize recovery factors and not have the interference you're asking about.
Operator
Our next question comes from Joseph Allman with JPMorgan.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
When we're looking at the wells in Washington County, is there anything geologically different that might make those wells vary from the wells in Guernsey County?
Barton R. Brookman
At analyst day, we presented a cross-section that showed the geology and, Joe, I guess I'd phrase it like this: we are probably within 90% to 95% similarity as we go up to Guernsey and over the Belmont and the overall geologic properties we're looking for an unconventional play. Probably the one thing we get asked about a lot is thickness.
We do have a deterioration in thickness of the Point Pleasant member from about 100 and 105-foot to 95 to 100-foot. So we lose 5% to 7% of our thickness but there are some other properties as far as some carbonate content and some other things that may attribute more to natural fracturing in the Point Pleasant that we're actually, on the flip side, more encouraged by.
So bottom line is, I think if we had the head of geology in here, we couldn't be more encouraged by all the data we have for our Northern Washington County acreage.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Got you. And so let's hope for the best but prepare for the worst.
So if those wells just don't work out as well, might that just focus you more on the Northern acreage and not do so much drilling on the Southern acreage?
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Well obviously, yes. If they don't work out, we wouldn't continue drilling there and we would turn to the Northern acreage and obviously, our Wattenberg.
But again, based on everything we've got right now and absolutely at the end of the day, IPs in production reserves will tell the story. But we're very encouraged by where we're at right now.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
Got you, okay. And then I just noticed, how many stages did you use at the Stiers wells?
Barton R. Brookman
An average of about 22 or 23 per lateral, if I remember right. I think mid-60 -- I think we pumped 65 stages total on the 3 wells.
Operator
Our next question comes from Ray Deacon with Green Capital.
Raymond J. Deacon - Brean Capital LLC, Research Division
So just a quick follow-up on Washington County. So I mean, this is really going to be the first well that far south and in Washington County, I guess.
What are your -- could you give a little bit more commentary on takeaway. I know you've got kind of a temporary solution, that's what you said, and I was just curious if you can extend that into something that would allow you to more fully develop the acreage if it does end up working?
Barton R. Brookman
Yes. The takeaway in midstream solutions in the southern acreage, I'm actually very encouraged by what Lance and his team have done.
We're in line with Blue Racer down there and they will be fully prepared, basically when we complete and cure the wells both on the Garvin and the Neill, to put those wells down line both from a -- those lines have been converted. My understanding is from dry gas transmission lines to wet gas gathering lines and will be feeding the Blue Racer plants.
So they've got the processing in place, they've got the gathering infrastructure as far as the bigger trunk lines, so right now, we feel pretty good about overall, where we're at. And if and hopefully when this acreage really pans out, I think our situation with Blue racer would be something we could add a rig in this area and have a drilling program and have reliable midstream services down there.
Raymond J. Deacon - Brean Capital LLC, Research Division
Got it, great. And just one more in terms of curtailments in the Wattenberg.
How much can you measure how much you're probably curtailed by high line pressures and how much you might be able to add just from taking care of that?
Barton R. Brookman
The answer is yes. Our engineering group can go in and do an evaluation of historical trends versus actual production and make estimates.
But it changes almost monthly based on the reliability, weather, so doing it accurately is difficult but we've got a pretty good handle. And we've made some presentations in the past about those impacts on curtailment levels in the basin.
As I've noted and Jim has noted, the bulk of these impacts have been to the old vertical wells that are more depleted and are much more sensitive to swings in line pressure and one thing that is happening in our overall production, particularly in the very northern part of the field, some of the older horizontal wells, not just PDC, but also all operators, are starting to show some impact. So October 1 is a very important day for us to see increased midstream capacities in the basin.
Raymond J. Deacon - Brean Capital LLC, Research Division
And just one more quick follow-up that occurred to me. With the Codell, can you remind me how much you booked last year?
And with the 15 wells you drilled so far, how much of the acreage is derisked for the Codell at this point?
Barton R. Brookman
Let me tackle the first one because I know that answer. We had virtually no Codell in approved category.
Last we had 5 PDP wells booked, but writer Scott [ph] was not at a point in the early development of the horizontal Codell to book puts in obviously, an approved category. We've got 455 locations identified in our 3P, which we've got fairly high confidence.
With time, those are going to flow into proved category. So, Ray, the perspective right now, since we took all of the vertical Codells off the books due to the 5-year rule, since it was not an operating practice of the company anymore, we have almost all of our Codell reserves right now are upside in the proved category.
Operator
[Operator Instructions] Our next question comes from David Beard with Iberia.
David E. Beard - Iberia Capital Partners, Research Division
Just a couple of questions on the Utica starting micro and moving macro. How many permits do you have now, or how many have you actually submitted?
And then the bigger question is, what do you think you'd need to see to move a second rig into that location over the next couple of years? And is that something you're contemplating?
Barton R. Brookman
The permit, I don't know if I can give you a quantity but I can give you a timeframe. The team around the 1 rig pace has permits that they are working on or have submitted through I think, the first half of next year.
So we're recognizing there's a lot of lead time and planning. We've got -- we're being very proactive in the permit process.
So we're comfortable pushing that 1 rig pace into next year. As far as adding the second rig, that is really going to be dependent, David, on the results we see on these wells that we're going to be bringing on.
We're gaining confidence there, we're looking at rig availability but we haven't even started the budgeting process for next year. I would think we will literally be looking at some initial rates and putting the budget together almost simultaneously as we decide on that second rig.
But yes, we have -- your question was are we contemplating that Jim has asked us specifically to be prepared for a second rig, so we've got some planning things we're doing. It's just we're going to want some data before we make that final decision.
Operator
Our next question comes from Ryan Oatman with SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Just a quick one from me. I saw Noble, they only did something like 100 or 125 completions in the first half of the year with 300 planned.
So I've had some questions about availability of completion services and whatnot in the DJ Basin. How do you feel about the back half of the year and what you have in terms of contracted fraceries and whatnot to compete this Niobrara program back half of the year?
Barton R. Brookman
Good question Ryan, because we're definitely seeing a -- I think there's going to be 60 horizontal rigs running in the Core Wattenberg area by year end. We are currently not seeing any strain on our side on the services.
In particular, on some manning and pumping services. Not only do we have a good plan in place for '13, we have already met with our provider on our '14 plans and have a commitment and a plan with them and assurance that they can take care of us.
So we're not seeing any strain to the PDC system right now, and don't anticipate as we go into next year.
Operator
Our next question comes from Irene Haas from Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Just a follow-up on the Utica play. With your 2 Washington County wells drilled, completed and sort of ready to be producing in October, do you feel better about your entire Washington County acreage and will there be plans to kind of push towards the south and edge of your land block in 2014?
Barton R. Brookman
Irene, without giving a lot of detail, obviously, drilling a well, you gain data, logging a well, you get data. We've done some deep pit pumping tests on the reservoir, we've gained some reservoir knowledge.
And I would classify my confidence and enthusiasm around Washington County as dramatically higher than it was even 3, 4 months ago before we drilled the well.
James M. Trimble
We have 2 more wells scheduled for the end of the year.
Barton R. Brookman
Yes. We have 2 more wells planned down there before the end of the year.
So 4 of our wells are part of the 11 planned for the year. So again, expect big news here in the next few months on Washington County and like I said, as we noted, we're currently completing the Garvin wells so that thing -- probably by the next week, we'll be in cure mode and for sales, as we talked about, should be relatively quick in the Blue Racer.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Have you disclosed the locations of those 2 extra wells in Washington County?
Barton R. Brookman
Yes, we have and it was on the map that I presented for the Utica in the slide presentation in turquoise boxes. It should be 2 -- it's 2 additional Garvin wells.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Okay, same location really, you're not going any further south?
Barton R. Brookman
No . Additional wells there.
And then the plan after that, based on the Neill and this would be a '14 plan, would be to move a little bit more to the west, towards the Neill well.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Okay. And would you venture into Morgan County at some point?
Barton R. Brookman
Probably right now, that will not be part of our 2014 data. On a relative term, we're clearly seeing being in the heart of that liquid-rich fairway or more to the eastern side [indiscernible] we're going to want to gain additional data.
Operator
I'm not showing any [indiscernible]
James M. Trimble
Well, I'd like to just say thanks very much. Appreciate everybody joining us today for -- and all the good questions, and we look forward to seeing you all soon.
Thanks.
Operator
Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.