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PDC Energy (NASDAQ:PDCE)

Q3 2012 Earnings Call

November 01, 2012 11:00 am ET

Executives

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

Gysle R. Shellum - Chief Financial Officer

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

Analysts

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

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

John Malone - Global Hunter Securities, LLC, Research Division

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

Mark Lear - Crédit Suisse AG, Research Division

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

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Operator

Greetings, and welcome to the PDC Energy 2012 Third 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. Gysle Shellum, Chief Financial Officer; Mr. Barton Brookman, Senior Vice President, Exploration and Development; 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, and good morning. Thank you for joining our call today to discuss PDC Energy's Third Quarter Results. Before I begin, let me draw your attention to the Safe Harbor language at the beginning of our presentation which will cover any forward-looking statements made today during our presentation. I will discuss the highlights of the quarter followed by Gysle on the financials, and then Bart on the operations.

For the third quarter, we had an adjusted net loss of $4.8 million or $0.16 per diluted share, which is net of unrealized gains on derivatives. Adjusted cash flow from operations was $33.6 million in line with our guidance, and adjusted EBITDA was $39.7 million; all are non-GAAP measures. We continue to have a strong operational execution in the third quarter. Total production was 12 Bcfe, an increase of 6% over the third quarter of 2011; and 36.6 Bcfe for the 9 months, a 14% increase over the first 9 months of 2011. 53% of our production for the quarter was attributable to the liquid-rich Wattenberg Field, where we and other operators continue to experience high line pressures that impacted our legacy vertical production. However, our horizontal drilling program continues to add to the growth in production.

In the Wattenberg Field, we continue to expand strong success with our horizontal Niobrara wells and now with our horizontal Codell drilling program. We have spud 22 horizontal Niobrara wells plus 6 horizontal Codell wells. In addition, we have drilled and completed 3 downspace in test so far this year with good results. We have 2 rigs running in the field at present, drilling from multi-well pads and expect to add a third rig in the mid-2013, as we prepare for the additional gathering capacity. We're working very closely with our third-party midstream provider and are seeing improvements in this area. But as we and others have reported, it will be mid 2013 before facility expansions are completed to provide a meaningful relief to this problem. We experienced a modest improvement in the third quarter, but October saw even more improvements with cooler weather and more natural gas demand on the system.

In our horizontal Marcellus Shale development, we completed a 3-well pad that has been delayed pending a pipeline river crossing permit. We expect to receive that permit shortly and we will begin construction as soon as the weather conditions from hurricane Sandy will allow, so these wells can be then turned into line. Once this has been completed, we will have all our wells on production and expect to add a rig here in the first quarter of 2013.

In the Utica play in Southeast Ohio, we have drilled 2 horizontal Wells in Guernsey County and completed the first one which is in its 60-day resting period. We expect to release the data once we have completed our flow test well, which we will begin around Thanksgiving. The second horizontal well is awaiting completion and we plan to reestablish drilling in this play in the first quarter of 2013. We continue to believe that Utica play has the potential to be a world-class shale development with our acreage being in the key liquids-rich fairway. Bart will provide more data and the drilling operations activity shortly.

We also took several steps since our last earnings report to strengthen our liquidity and balance sheet, which I will let Gysle cover in his comments. In summary, we continue to focus on drilling efforts in the liquids-rich areas and are committed to increasing the percentage of liquids in our portfolio through the development of our well-positioned assets as we strive to add value for our shareholders. I will now turn the call over to Gysle for his financial review of the third quarter

Gysle R. Shellum

Thanks, Jim, and thanks, everyone on the call for joining us this morning. As usual, my comments will be high-level. So for a more complete analysis of our third quarter results, you should refer to our press release and our 10-Q filed earlier this morning. After my discussion of results for the quarter, I'll briefly address our expectations for the full year.

Looking to the summary of financial results for the quarter, total sales, excluding realized hedge gains and losses declined to $59.9 million or about 17% decline compared to the third quarter last year. As Jim mentioned, production during the quarter was up about 6% on an Mcf equivalent measure, but sales were impacted by lower natural gas and NGL prices compared to last year. Natural gas sales dropped 34% compared to our third quarter 2011, in spite of a 10.5% increase in production between periods. Weaker NGL prices also reduced the impact of an 8% increase in NGL production during the quarter. NGLs accounted for only about 8% of total sales in the current quarter.

Crude oil sales for the quarter decreased a little less than 7% compared to the third quarter last year. The decline is a combination of production curtailment in Wattenberg and inventory swings of over 25,000 barrels between quarters. Crude oil realizations were the only bright spot for pricing showing a 4% improvement in the current quarter compared to last year's third quarter. Overall third quarter production came in at 12 Bcf equivalent compared to 11.3 Bcfe in the third quarter last year. Our weighted average wellhead price for this quarter was $5 per Mcf equivalent, $1.37 decrease from the third quarter 2011. Our weighted average wellhead price included -- including realized hedge gains for the quarter were $6.09 per Mcfe compared to $6.81 in the same quarter last year. More detail of commodity prices can be found in our 10-Q filed this morning.

Production costs for the quarter were $20.8 million or $1.73 per Mcf equivalent compared to $1.21 in the third quarter of last year. About 27% of the -- $0.27 of the increase in the current quarter is attributable to nonrecurring charge related to the acquisition of Wattenberg assets in late June this year. Also last year's third quarter number was reduced by about $0.27 per Mcfe due to a nonrecurring credit to operating costs resulting from an amendment to a firm transportation agreement in that quarter. Adjusted for these 2 nonrecurring events, production costs per Mcfe would've essentially been flat between quarters. Lifting cost grew slightly upward to $0.89 per Mcf equivalent in the current quarter compared to 82% -- $0.82 in the same quarter last year. Also we added a new line on our statement of operations this quarter and adjusted the third quarter last year to present accretion of asset retirement obligations separate from production costs. These noncash charges are becoming more material as a result of our recent acquisitions, so we followed the lead of most of our peers and presented them separately. The production costs presented here exclude accretion from asset retirement obligations.

Margins from continuing operations decreased to $39.1 million in the quarter, driven by the decrease in sales. The margin for the current quarter is about 65.3% of sales compared to 81% of sales in the third quarter 2011. Part of the reason for the decrease in margins between periods, is the 2 nonrecurring charges I just mentioned. Adjusted for these events, operating margins would've been about 71% and 77% for the current quarter and the prior quarter 2011, respectively. The variance is substantially all attributable to pricing.

Similar to our second quarter, realized hedge gains cushioned the impact of lower commodity prices in adjusted cash flow from operations and adjusted EBITDA. Net pretax realized hedge gains were $13.1 million in the current quarter compared to $14.9 million in the third quarter 2011.The difference you see between quarters for adjusted EBITDA and adjusted cash flow relate to the same forces impacting operating margins.

Adjusted EBITDA per diluted share in the current quarter was $1.31, compared to $2.35 in the third quarter last year. Basic weighted average shares outstanding in the current quarter were $30.2 million, compared to $23.6 million in the third quarter 2011, the result of our May 2012 equity offering in conjunction with the acquisition of Wattenberg assets that closed in late June.

DD&A from continuing operations increased to $32.5 million in the quarter compared to $31.5 million in the third quarter last year. The increase is mostly attributable to the increase in production between quarters. The DD&A rate related to oil and gas production decreased from 26 -- $2.64 per Mcf equivalent in the third quarter 2011 to $2.56 in the current quarter. And G&A expenses were $13.7 million this quarter and identical to the same period last year.

The top half of our next slide reflects net income and loss for the quarter per generally accepted accounting principles, which includes unrealized gains and losses from mark-to-market hedge positions as well as discontinued operations in 2011. We recorded net after tax unrealized hedge losses of $27.8 million in the current quarter compared to net after tax unrealized hedge gains of $25.6 million in the third quarter 2011. These unrealized gains and losses in each quarter are the difference between GAAP net income and adjusted net income presented in the bottom half of the slide. There is a reconciliation of GAAP net income and adjusted income in the appendix of this presentation and in this morning's press release as well.

For the current quarter, we recorded adjusted net loss of $4.8 million compared to adjusted net income of $6.8 million in the third quarter last year. The difference between quarters can be attributable to lower -- attributed to lower commodity prices and the curtailment in Wattenberg in the current quarter that I mentioned earlier.

The debt maturity schedule on Slide 9 is pro forma for our $500 million high-yield placement and pro forma for the call of our outstanding $203 million, 12% bonds. Proceeds from the offering were used to retire the 12% bonds and the remaining funds reduced our revolver borrowings to about $40 million as this bar chart shows. Our revolver borrowing base redetermined was completed earlier this week. The availability under the revolver was adjusted downward by $75 million to $450 million. Our credit agreement requires a reduction in our borrowing base equal to 25% of any incremental senior debt issuances. So with the sale of our 7.75% bonds and the retirement of our 12% bonds, we gave up 25% of the incremental $300 million of new senior debt, or $75 million. Other than this adjustment, there were no other changes to our borrowing base.

Pro forma liquidity under the facility at September 30 is about $408 million. This graph also does not show our 50% share of a Marcellus joint -- separate joint credit facility.

On the hedging front, we added some 2014 oil and gas hedges since the last quarter. We still have a ways to go to get where we want to be in 2014, but we're more than half the way there based on the restrictions in our credit facility. We used a combination of swaps and collars for oil hedges and mostly swaps for natural gas hedges. We also recently finished buying back the ceilings on all but a very small volume of our natural gas collars through the remainder of this year and all of 2011. We had over 60 Bcfe of gas hedged with about $6 by $8 collars in 2013 and 2012. We didn't see much chance of being limited by the ceiling and the market agreed with us, so it was very inexpensive to cover these calls. The reason we did this is because the remaining floors or puts don't count as hedges under our credit facility restrictions, so we are freed up to hedge additional gas volume in 2013. That's the reason there are no ceilings in 2012 and 2013 on the natural gas chart in the bottom of this page.

Slide 11 is a look at our average realized sales price per Mcf equivalent for the first 3 quarters of 2012 compared to our pricing guidance for each quarter and our projected pricing for the fourth quarter of 2012. Sales prices per Mcfe on this chart include realized gains and losses from hedges in the periods presented. Our estimated price realization for the full year averages $6.31 per Mcf equivalent. We did a little better than expected in the third quarter mostly because natural gas prices showed some strength during the quarter. In spite of our challenges in Wattenberg this quarter and last quarter, we believe we will finish the year within the range of our guidance for adjusted EBITDA and adjusted cash flow from operations. Adjusted net income will be impacted in the fourth quarter by a charge for early extinguishment of our debt related to our 12% bonds. Pretax charge will be approximately $23.3 million, including may call [ph] costs, unamortized debt issuance costs and original issued discount. Consequently, 2012 adjusted income will fall below our range. Absent this event, we believe adjusted net income would also fall within the range of our guidance. With that, I'll turn it over to Bart for comments on operations for the quarter.

Barton R. Brookman

Thank you, Gysle, and hello, everyone. Production as Jim noted for the quarter was 12 Bcf equivalent, a 6% increase from the third quarter of 2011. Once again, the DJ Basin is the company's largest producing asset at 7.1 Bcf equivalent, followed by the Piceance Basin at 3.3 Bcf and then the Appalachia Basin at 1.6 Bcf, and that is our net within the JV.

An overview of the company's production. Again, a very challenging quarter for our Wattenberg operating team. Corporately, again, 12 Bcf was produced. We were 0.7 Bcf off our expectations. All of this production shortfall was due to the high line pressures we continue to experience in the Wattenberg Field directly impacting our legacy vertical production. It is important to note all other basins in the company and the capital programs are performing at or above our expectations. And in particular, our horizontal program in the Wattenberg Field is producing at 5% -- 5% above our engineering expectations. This horizontal program is now 14% of the company's production and growing. We have spud 22 horizontal wells this year in the Niobrara and 6 horizontal wells in the Codell formation and I will update you more on these programs in a moment.

Production by area. Wattenberg, again, our largest producer within this field right now. We have a 60% liquid mix for the total production from the field. The base for the Piceance Basin is our second largest producer followed by the Appalachian Basin and then NECO. The liquid mix for the company, as you can see, remains at 33%. This is down slightly due to ethane rejection mode we continue to experience in the Wattenberg Field, thereby reducing our overall NGL yield on the company's production stream.

Let me see if I can explain what's going on with the midstream situation in Wattenberg. The bar graph you see is the average daily throughput of our primary gather in the Wattenberg. In the third quarter, we anticipated an improvement in the gathering system throughput particularly in September as temperatures cool. As you can see from the graph, that did not happen. This resulted in continued, abnormally high line pressures. And again, this was the primary cause of our production shortfall in the quarter. The good news is, as you can see, the past several weeks we have seen improvement in the total system throughput due to cooler weather conditions in October and a series of small system improvements by the gathering company. We are currently seeing modest improvements in line pressure which directly correlate with this overall improvement and throughput.

When you look at the next slide, you can see the impact on the Wattenberg production. The combined gray and copper bars represent expected production from this basin. The gray portion of the bar graph being the actual production for the quarter and the copper color being what we show as curtailed volumes within the Wattenberg Field. The line pressures are showing improvement. We are seeing improvement in our overall production as shown by the October estimate.

We'd like to clarify a couple of things here: First, the production shortfalls shown here are only amongst our vertical legacy wells, again, due to higher line pressures in the field. Second, our horizontal program is performing very well and is currently estimated to be at the level of 5% above our engineering expectations.

To give a quick overview of the drilling activity for the company. 12 wells were drilled this quarter, 11 of those in the Wattenberg, 1 in the Utica, all horizontal. We executed on 32 refracs or recompletions in the Wattenberg Field and participated in 6 non-operated projects. Currently, we are running 2 horizontal rigs in the Wattenberg Field. From a drilling standpoint within the Wattenberg, we are on target for our 37 wells to be spud this year. We are beginning to see a contribution from the second rig that we added in July. Currently, we are drilling our fifth downspace pad. 3 of those downspace pads are in production mode with very encouraging results. I should note these 3 that are online are all a 12 horizontal well equivalent per section. We have drilled 6 Codells. We are on target to spud 10 Codells by year end and we also have 1 Niobrara "C" Bench test plan by year end 2012.

An update on our horizontal Niobrara and Codell drilling. You can see our horizontal Niobrara program, which is represented in red, continues to average around 340,000 to 350,000 Boe reserves per well. We are very, very pleased with the overall performance of this program. Equally exciting for us is our horizontal Codell program. You can see the green line which continues to perform at the upper end of the type curve range is our first horizontal Codell. And our second horizontal Codell well, which was choked back in the first 30 days to production pad facility constraints, was recently opened up and is cleaning up to fall within our type curve range. As I noted earlier, 28 wells have been spud in these 2 programs this year, 6 of those Codell. Our cost structure remains at $4.2 million per well and again, this program is exceeding our engineering expectations.

On the CapEx side, our developmental capital right now is on target with our budget for $186 million. You can see $182 million of that is in the Wattenberg. Our exploration leasehold is currently on trend for $102 million for the year, the bulk of that being in Utica for exploration drilling and a larger extent, the leasehold acquisition within the Utica project. You can see we have $327 million in the Wattenberg for acquisition. The acquisition this summer bringing our total CapEx anticipated for the year to $615 million. And within our Mountaineer division we anticipate spending $27 million, that is PDC share, and this is fully funded within the joint venture.

Lifting cost overview. Overall, we are very pleased with the operating cost structure of the company. The quarter came in at $0.89 per Mcf lifting cost. We're on target for about $0.91 per Mcf for the year 2012. You can see we're right in line, overall, with 2011 lifting cost levels. Some improvements to note: We have ongoing improvements in the Piceance due to water management. We are now disposing within our operations in the field, 100% of our produced water. We did experience a slight decrease in our overall work-over expenses. Those coupled -- those items coupled with increased production help for ongoing improvements in this measurement.

So in closing, some operational highlights. The third quarter in the Wattenberg Field, our horizontal production averaged 3,000 barrels equivalent per day. I am happy to announce, the current levels as of this week are approaching 5,000 barrels a day, so we're seeing a dramatic ramp up in our horizontal production. We deployed our second rig in July. Our costs remain at $4.2 million per well. We have 3 downspace projects completed and very early online with what I would classify as very encouraging results. As I noted earlier, when we have a Niobrara "C" Bench test plant, this will be, hopefully, online by year end.

Our reserves for our horizontal program continue to fall within our type curve range, and we are seeing a 70% to 80% liquid contribution from this program as we focus on the north portion of our acreage position. We have fully integrated the Merit assets and we have intense planning right now with their primary gather on a short and long-term bases within this basin. In the Marcellus, our Devonian production was very strong for the quarter. As we noted, we have one 3-well pad that is completed. It is ready to produce. We are waiting on pipeline. And as Jim noted, we have some delays in the regulatory side for a Corps of Engineer permit to cross the river. And then as of this week, hurricane Sandy brought conditions that we must wait probably another 2 weeks before we can begin implementation of that river bore. Currently, we are also reviewing drilling rig availability for early 2013 within the Marcellus.

In the Utica, we have secured our 45,000 acres and have clean title. The majority of our acreage is in the liquid-rich window. We've drilled 2 horizontal wells in Guernsey County. Other operators have some fairly significant initial rates that have been announced around our acreage position. We will complete a flow test on our first horizontal well in late November and report this information to you in mid-December. Our second horizontal well completion in the Utica is scheduled for early December. We are currently sourcing a drilling rig. It should be deployed sometime in January -- hopefully, mid-January of next year. And we are evaluating multiple midstream options and anticipate second quarter of 2013 for first sales on this project.

And in our Piceance, our production is exceeding our expectations. We have a production focused work-over program that has been very successful. This is an area we're focused on operating cost reductions, production optimization. Our operating team here has done a wonderful job of keeping this asset moving along. So with that, I'll turn this back to the operator for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Welles Fitzpatrick with Johnson Rice.

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

If we look at Slide 17, I'm just trying to mesh that with what I read as fairly cautionary language in the release on fourth quarter production growth. On Slide 17, you've shown about a 20 million cubic feet a day increase and do you think that October is not indicative of the fourth quarter? Or are you assuming some sort of change on the ethane side in that slide? Or was that fourth quarter commentary in the release more related to Marcellus permitting issues?

Barton R. Brookman

Well first of all, Slide 17 is only Wattenberg production. Second, there is no change in the ethane recovery assumptions in the October estimate here. On the 20 million a day wells, I assume you're going from the top of the gray to the top of the gray?

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

Right.

Barton R. Brookman

Okay. That is the rebound for 2 reasons. First, we have had some fairly large pads that have been brought online, which I noted. And then the second thing is we have seen this relief, and again, it's a modest relief in line pressure. I don't want anyone to think we're back where we were in first quarter, but we are -- that is helping some of the vertical production in the field. So there's multiple things going on there. Did I answer your question?

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

Yes, that's perfect. And then on the "C" test in the Niobrara, are you guys planning to drill that adjacent or above and below respectively, existing Codell and Niobrara "B" wells?

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

It is part of a downspace with Codells and Niobrara "Bs" integrated and I don't have the plot of the exact pattern. But I can tell you it's either a 12 equivalent well pattern or 16 equivalent well pattern and there will be Codells and Niobrara "Bs" around it.

Operator

Our next question comes from Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

I think Welles kind of touched on what I was going to ask. It looks like -- I mean, we're seeing this Wattenberg come back sooner than expected. I mean, do you anticipate a further recovery into 2013 for production? Or based on this October guidance, do you think we could see it as early as this fourth quarter?

Barton R. Brookman

I think we have to be cautious of presenting bull relief in 2013 because there's a lot of drilling going on here. And I think, as Jim noted, we're really looking at the facility start up and mid '13 as the full solution. I think, as we go through winter, Ryan, we will see improvements. We've got field usage due to cold weather that improves the throughput on the system. We've got colder weather. We'll have freezes which knocks some production off. There's a variety of things that happen along with the cooler weather, helping the compression efficiency. So I think we're going to see a rebound similar to this October. And again, we still have some volumes we're leaving in the ground relative to our expectations. But I think we're going to see a better fourth quarter. I think we'll see a solid first quarter. We're doing everything we can in our '13 guidance to try to model this as we go into next spring and summer while these facilities start up. But that is a difficult challenge for our engineering teams because we don't know what the weather is going to be like and there's a lot of drilling rigs running off of our gathering system right now. So hopefully I answered your question.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Yes, yes. That makes sense. And then shifting now to Utica, I mean, we've seen offset operators report wells that come on at anywhere from 2,000 to 5,000 barrels a day. I mean, a, do you guys have any expectations for these Utica wells? And then if you see sort of similar success, is that $50 million 2013 budget flexible or does infrastructure and et cetera, kind of preclude that number from moving higher?

Barton R. Brookman

And Jim's here, so he's staring me down while I answer this question. We have very, very high expectations on this project. We're excited by the rates that you referred to. And as an internal operations and engineering company, we want to get our own production, our own IPs to report to you guys. And I would classify the $50 million that we've announced to you as flexible based on results. We're always going to look at our opportunities and try to allocate our capital to the best projects. So if these wells come on anywhere near -- and I should clarify, hold up, and that will take several months of production on the wells, I would anticipate you'll see us try to, at least consider, keeping a rig running for the full year. But again, that will happen as we get our own internal data.

Operator

Next question comes from John Malone with Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Just sticking with the Utica for a moment, can you talk at all about your plans for -- in the Washington County and what you're seeing in the southern part? I mean, you got a lot of acreage down there. And are you going to be drilling that out to see what you got in 2013?

James M. Trimble

Hey, I can just jump on that for a second there, John, and just -- what we've got is we're getting a rig and I think as Bart said, we're looking at a rig coming in and hopefully in January of next year, in '13. We will probably tackle -- the very first thing will be an offset to the Miley wells that have been drilled with the idea, we'll go down and drill in Washington County, probably end of first quarter, beginning of second quarter.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And will those be sort of vertical test or will you start out horizontal? How are you going to approach that?

James M. Trimble

We're going to go straight to horizontal. So I think you're through seeing us do any verticals.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And just so I understand, you're talking about getting a rig now. That will mean 1 rig running through the year?

James M. Trimble

As we were just talking about, what we've got is we're picking up a rig. We've allocated about $50 million in the drilling programs for next year. That only takes us through about half of the year. We're waiting to see what the results are and as Bart said earlier, we're going to be very flexible with the budget. If everything's coming in, we're getting the -- we're scheduled right now to have the infrastructure in place that we're looking at some time in the mid-second quarter, having production. If all that comes to fruition and the wells look great as everybody elses, I think you would look at us continuing to drill for the full year.

Barton R. Brookman

We're working -- currently working on a rig arrangement that gives us the right to drill 5 with no obligation after that, but a first call on the rig if we want to extend the drilling program in 2013. So I think the drilling -- the company we're working with has done a great job of helping us a layout kind of the delineation of this Utica early for the company.

John Malone - Global Hunter Securities, LLC, Research Division

Okay, okay. And just one housekeeping question. You refer in that notes to the fact that you're bringing production guidance down to 51.5 Bcfe, but that you expect to keep your full results for adjusted EBITDA and cash flow within the range of prior guidance. Can you remind us what that prior guidance range was?

Gysle R. Shellum

Yes, this is Gysle. I can do that. Just give me a second here. We had for EBITDA, on the low side $191 million, on the high side $212 million. And adjusted cash flow from operations was $145 million on the low side, $164 million on the high side.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And you're still within that range in this expectation for the year?

Gysle R. Shellum

Yes, sir.

Operator

Our next question comes from Irene Haas with Wunderlich Securities.

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

I just want to get a little temperature reading from you guys regarding the Marcellus. Any enthusiasm into putting some money to work from your JV next year?

James M. Trimble

Yes, I was going to say, what we've announced is that we're planning on bringing a rig in first quarter of 2013, with the idea that we're -- with fully intent to keep that drilling through the year. As we've said, we're working -- we will be starting our river bore shortly. And once we get that in we'll have everything ready to go. We will have all our wells on production then and we will start drilling along those facilities.

Operator

Your next question comes from Mark Lear with Crédit Suisse.

Mark Lear - Crédit Suisse AG, Research Division

Just in terms of infrastructure in Wattenberg, just was wondering if -- I know there are a lot of -- there's a lot of expansion on the way in the back half of '13. I guess, is there any possibility for you guys to do some self-help there in terms of drilling in, I guess, lower GOR areas to kind of put some -- get some relief on the system?

Barton R. Brookman

Mark, the answer is yes. We're trying, we're doing our best. Our land situation in some form or fashion is helping dictate our drilling program, but we are focused on the northeast portion of the field where we're more like a 2,000 GOR. It's at 70% to 80% liquid. We're trying to minimize the amount of gas right now that we're generating from our drilling program, which eventually ends up being gathered on our primary gatherer system. So the second thing we are doing, we currently have 80 wellhead compressors in the field, selectively placed through the field and we plan on expanding that wellhead compression to help optimize our overall production. So we've got George and our midstream team here and our district out there working diligently to try to come up with solutions short term. We're also working with DCPs. They've got a lot of creative ideas to try to help capacity here in the next 6 months with some small additional expansions and some fairly creative options that may add another 40 or 50 million a day of throughput capacity out here. But as Jim noted, the biggie is next summer when the plant starts up and adds significant volume improvements to the basin.

Mark Lear - Crédit Suisse AG, Research Division

Got you. And then, I guess, with the expansion, I mean, can you maybe -- there does seem to be some confusion in the market how, I guess, this recent July expansion and, I guess, the future expansions, how that capacity is allocated and, I guess, how you fit into, I guess, that expansion itself, or how -- what percentage of the volume capacity you get. I mean, can you maybe speak to that a little bit, whether it's a firm capacity agreement or how that works your agreement with DCP?

Barton R. Brookman

Let me take a stab at this. First of all, there are no firm volume commitments on the gathering side of the pipe for any of the operators. All operators produce into their system on, I would classify it as a best efforts basis, and they deal with the field pressure that they experience in the different parts of the field. So it is the responsibility of the operator to either add wellhead compression or diligently produce the wells to the best of their ability. But DCP doesn't selectively go out and say, "You're allowed to do this, you're allowed to do that." Okay. You go in and legitimately try to produce your production into their system. The choke on it is the total throughput capacity of their plants. So we're all trying to grab that space, basically. I can tell you this, Mark, our proportion of the system throughput on our gather, runs about 22% to 25% of their total system throughput. And that number has been fairly consistent whether it's got -- whether their throughput was in that 380,000 level that I presented or that 430,000 level I presented. So as their throughput goes up, we have seen our throughput on the system hold relatively level in that 22% to 25% range. Does that make sense?

Mark Lear - Crédit Suisse AG, Research Division

Yes. It definitely does. I guess the one thing I found a little curious was that you did perform some recompletions in the quarter which I guess -- my view is that it might not help the situation with the vertical wells, I guess, being curtailed. I was just wondering what the thinking was behind that activity?

Barton R. Brookman

We slowed that program down and -- I'm trying to recall, we slowed that program around the August call, if I remember, but we already had -- we made that decision in early August. We had already initiated work over rigs and pulling tubing and perforating on a good batch of those. Some of these are still selective candidates that we implement while we drill the horizontal wells. So they are very good candidates. We don't want to go drill a horizontal well and then have an offset vertical that we want to do a Codell refrac on, because we don't want to frac into one of our biggest producers, being that new horizontal well. So Mark, we do have some select cases where the team elects to execute on those. But we're trying to minimize the number of refrac recompletes we're doing in the basin. And next year, you see it'll be -- we'll still have some activity here but it will be minimized, and it'll be tactically designed around our horizontal program.

John Malone - Global Hunter Securities, LLC, Research Division

Got you, got you. And I guess, one last quick one just, I guess, regarding other potential in the Wattenberg. I know some other operators talking about the A. Do you have any plans to test the Niobrara A zone?

Barton R. Brookman

In a non-operated fashion, yes. We've got some AFEs from one of our big brothers that they are testing the A, so we're going to get that data. Right now, we don't have it in the books for us to go actually drill one.

Operator

Our next question comes from James Vice with Wells Fargo.

Unknown Analyst

A couple of questions. I guess, back on the infrastructure in the Wattenberg, can you just remind me what the -- how much of your production right now is coming from your vertical wells versus horizontal? And how you expect that production to trend over the next year?

Barton R. Brookman

Let me go to the third quarter. Total Wattenberg production for the third quarter, yes, we're in the $75 million, $80 million equivalent and about -- well, I think I noted, the horizontal production was about 30%, I believe, of the -- actually, Lance is helping me here, 26% of the third quarter production in the Wattenberg Field was horizontal.

Unknown Analyst

And do you expect the production from the vertical wells to sort of enter into a base decline rate or are you looking to keep that relatively stable with your were recomplete program?

Barton R. Brookman

Well I would hope the next several quarters, the next 2 quarters as we go through winter, we'll see our vertical production rebounding. So we'll be on a temporary incline and then I would expect it, once we get the facilities up and running next summer, to go to its normal terminal decline which is, I think, about an 8% for the field. But you will see a very dramatic increase proportionally of the horizontal drilling program, particularly as we add a third rig next year relative to the overall vertical production. So what you can expect in '13 and definitely in '14 is for that horizontal program to grow tremendously and that vertical production, hopefully, if we're maintaining system facility pressures, to be on a normal terminal decline.

Unknown Analyst

Great, that's helpful. And then secondly, can you just remind me what the incremental capacity is that you see coming online with the facility start-up in mid-2013?

Barton R. Brookman

Bear with me for a second. I think I have a plot here. If you go back to Q -- the prior Q call, there was a slide in there that represented the facility expansions and I'm trying to find it. I got it right here. Mid-2013 you will see 110 million a day expansion, scheduled to come on, I believe, June- July timeframe. And we expect to see full benefit of that probably in September timeframe. And again, that will be 110 million a day and then there's a secondary expansion to that, that will happen late in 2013, so another 50 million a day. So by year end 2013 -- okay, I think the current capacity of the system is just under 450 million a day, you're going to add another 160 million to that. So whatever that total is, 500 million, 600 million -- just in the low 600 millions. And then equally important for the long-term viability of this basin and capacity, in 2014, our primary gatherer has another 230 million a day plan scheduled. So by the end of 2014, we expect a throughput capacity of their system of 835 million a day. And if you go back to the slide that showed the throughput, I think the October estimate is in the 430 million range. So they're taking it from a current throughput level of 430 million to 835 million a day. And they're investing over $1 billion on this project.

Operator

[Operator Instructions] Our next question comes from David Tameron with Wells Fargo.

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

Just a couple of questions. Wattenberg, can you talk about well cost. The $4.2 million, is that -- what should we track into next year? How should I think about it?

Barton R. Brookman

I can tell you this, that's what -- we've told the market we're in a steady-state mode. And David, it's kind of an up-and-down situation. We've got some things that are pressuring us upward due really to the activity levels and I'll call it a demand pull on the services side. But we also have some efficiencies on the pad side, water management, centralized facilities. So overall the $4.2 million is a good number.

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

Okay. And I think we've talked about this, but remind me, 10%, if you get normal weather this winter, is that about an 8% to 10% moving capacity, just on line pressures and weather impact?

Barton R. Brookman

10% for the throughput?

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

Yes, for the throughput.

Barton R. Brookman

I would hope. Let me see if I can answer that a different way. I would hope that the system throughput will approach their name plate, that 434 million, 440 million a day on a consistent basis. And that would relate to definite improvement from the third quarter levels. But for me to say 10% more, I don't have those numbers in front of me.

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

Okay, okay, that's fair enough. The partnerships -- are there any -- if I just think about those for next year and are there any capital requirements either on the Piceance or the DJ, that you have to make to fulfill some those capital -- some of those partnerships and is there any impact from vertical versus horizontal for those?

James M. Trimble

No, as it relates to the partnerships, there isn't anything we've got to do in vertical drilling that relates to any of that.

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

Okay. And then last question, Barrett went out and -- Bill Barrett went out and sold some Piceance today. Are you guys -- I know everything is always for sale, but if you look at the non-core assets you have, or however you want to define them, do you have anything on the board like the Piceance or anything you'd look to divest right now besides the Utica, potentially?

James M. Trimble

No, we're really not looking at doing any divestitures at this point. We're always looking at different stuff and as you recall, last year, we were talking about NECO, and then we pulled it back. With gas prices still where they are, we'd probably get as much in cash flow from the properties as we would get from selling. So we're really looking to hold on.

Operator

Our next question comes from Ravi Kamath from Global Hunter.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Four questions. One, I think you guys have provided an exit rate guidance for production of 154 million cubic feet per day for 2012. Is that still good or that's -- nnything you can comment on that?

Barton R. Brookman

Right now, we're going to stick with that number. There are 2 factors that could impact though. The first is the timing of this third Marcellus pad coming on. Our original models, we had that coming on November 1. It's actually going to come on late-November now. So that pad will be producing at a higher rate. The second thing is we have one significant large pad in the Wattenberg Field that we are trying to get on mid to late December. We've had a couple of small mechanical issues there, so the operating team has delivered a warning that may not come on until early January. And then we have all the weather issues and snow in the Wattenberg Field. So we've got some moving parts on that, Ravi, but overall, the quality of the projects coming on aligned with the current base production of the company, aligns with that 154 million a day.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

And how much was the expected production from the Wattenberg pad?

Barton R. Brookman

I don't have that number in front of me. But I believe it's a 7-well pad, so it's going to be significant. Just to clarify, it's an issue of it that we're not to come online. It's an issue of it not coming on December 20 versus January 8.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Got it. Yes, just timing, yes. And then I realize that it's kind of early, but any kind of color you could provide on 2013 CapEx?

Barton R. Brookman

Well I mean, what we've said to the market is, what we're looking at right now is we're doing our budget and what we're projecting is around something very similar to what we ran this year.

Ravi S. Kamath - Global Hunter Securities, LLC, Research Division

Okay. And this year is running at what level?

James M. Trimble

Roughly, close to $300 million. So -- and the thing to remember is that we had about $90 million in the Utica, $65 million of that was for leasehold. And we won't be spending leasehold money next year and Utica will be using the money for drilling.

Operator

Our next question comes from Ryan (sic) [Raymond] Deacon with Brean Capital.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

I was wondering what do you expect well cost to be in the Utica and what were they on the first horizontal?

Barton R. Brookman

We're in the $9 million range on the first ones. I think our operating team here right now -- we've got some science. We're spending money on some MicroSeismic, some extra logging ones, different things we're doing. I'm going to say these first 5 wells are going to be -- let me clarify, the 5 wells next year will be in the $9 million range. Long term, we're working on, obviously, not as much science and some modifications to our overall wellbore designs and casing strengths, that I think on an ongoing basis we could push that number to 7.5 level. But again, we've got to get in here and really fully be active, drilling and completing wells. We will be on a pad basis, probably going for 3 to 5 wells from a pad. That's going to help. But it's an expensive basin with -- in particular the location costs, the weather make it very challenging and the road systems. There's a lot of things going on with upgrading roads for the bigger rigs right now. So we're still learning, is my point.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Okay, got it. And I guess, has anything occurred recently that is -- make you more optimistic about results that you should see in your southern acreage in Washington County and the Utica?

James M. Trimble

There's really been no activity down in the south, other than leasing activity. There's really been nothing that's changed our opinion and we still believe it's a very strong area for us. And just on the data we have in-house and the information, we believe that it's going to be just as strong as the rest of the areas that we have.

Barton R. Brookman

And Jim noted we're going to begin drilling hopefully in January, up in the Guernsey County area. We would've liked to drill the first well in Washington County, northern Washington. I was talking about these roads. The road use agreements with these counties right now is a fairly significant process and that is actually the delay right now in that northern Washington. So we're going to deploy that rig up to where we already have the road use agreements worked out, drill a 3-well pad and then proceed down to northern Washington, and as Jim said, sometime in probably April, we'll be down there drilling.

Operator

Our next question comes from Brian Kuzma with Weiss.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

A couple of quick questions here. One, I want to make sure I got how many horizontal Niobrara wells you guys actually brought online in Q3 and thus far in Q4?

Barton R. Brookman

We completed 10 in Q3 and I don't know if I have the Q4 number for you, Brian, so far. I don't have that number in front of me.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

But there's one big pad that's been completed in October in addition to those 10.

Barton R. Brookman

Yes, there's an IP of, I believe, one significant pad in October. If you're trying to tie it back to the production jump on the graph, there's 2 factors that went in to that: obviously, better line pressure in our vertical production rebounding, and initial rates off of our horizontal drilling program. It's that quantity number I don't have in front of me for October.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

And then I guess I just wanted to try to summarize on the midstream issues here, that if you guys -- if I look at your production in October, and you guys are just curtailed by a little bit and throughput is, you're saying going to go up a little bit from some small DCP projects, I guess I just wanted to understand how production can keep growing other than just like your mix getting a bit more oily or something like that? Did that question make any sense?

James M. Trimble

Well I think 2 things are what you're looking at is, I think capacity -- they've gotten their capacity, which on a Slide 16 Bart indicated is in the 430,000 range. But as the weather gets cool and demand grows, line pressures are coming down. So that's -- what you're seeing is the improvement in line pressure. That's going to be the main thing that's going to help for the rest of the year. So it's not anymore facilities that they're adding, it's really the efficiencies of the compressors and demand.

Barton R. Brookman

They are working on a creative solution, which I won't go into too much detail, to possibly push this total throughput over 450,000. We haven't got final word on that yet. So that would be a incremental help, Brian. And then you also have field usage in the field in winter time which is, we think, about 20 million a day out here that is burned on location just to keep everything warm on location. So you've got a reduced deliverability at the wellhead and hopefully additional incremental capacity on their side. I don't think we can lose sight on the fact that we -- to Jim's opening comment, next summer is the real solution, when we go to that 600 million a day range for the total system throughput.

Operator

I'm not showing any further questions at this time. I'd like to turn the conference back over to Mr. Trimble for closing remarks.

James M. Trimble

Well, thank you very much and I'd just like to say I know today is a very busy day for everyone and I appreciate you joining our conference call. That concludes today's presentation. Thank you.

Operator

Ladies and gentlemen that concludes today's presentation. You may disconnect and have a wonderful day.

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