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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

Lance A. Lauck - Senior Vice President of Corporate Development

Analysts

John Malone - Global Hunter Securities, LLC, Research Division

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

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

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

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

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

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

David E. Beard - Iberia Capital Partners, Research Division

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

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

PDC Energy (PDCE) Q4 2012 Earnings Call February 27, 2013 11:00 AM ET

Operator

Greetings, and welcome to the PDC Energy 2012 Fourth Quarter and Year End 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 now begin.

James M. Trimble

Thank you. And good morning, and thank you for joining us today to discuss PDC's fourth quarter and year end 2012 results.

Before I begin, let me draw your attention to our Safe Harbor language at the beginning of our presentation which will cover any forward-looking statements made today during our presentation.

I will discuss some highlights for the quarter followed by Gysle on the financials, and then Bart on operations. Both will provide additional detail.

Overall, the fourth quarter and full year for 2012 was an exciting and excellent period for PDC. Although we realized a net loss of $126 million or $4.17 per diluted share, or $131 million for the year, the losses were primarily a result of 2012 commodity pricing and impairments related to the previously announced expected asset sale in the Piceance Basin, plus the extinguishment of debt related to the early redemption of our 12% Senior Notes in the fourth quarter. Gysle will expand on this shortly.

Net cash flow from operations increased 4% to $174 million for 2012 compared to $167 million for 2011.

We continue to have a strong operational execution in the fourth quarter. Total production was 13 Bcf, an increase of 2% over fourth quarter '11 and 8% over the third quarter of '12. Growth was driven by all 3 core operating areas. For the full year, the company produced 49.6 Bcfe from continuing operations as compared to 45 Bcfe in 2011, a 10% increase. We also decreased lease operating expense on a per Mcf basis for the full year of 2012. In keeping with our stated goal to increase oil and NGL production percentages, liquid production increased to 36% in the quarter with Wattenberg production accounting for 99% of the crude oil and NGLs. This compares to a ratio of 33% liquids in the third quarter, 2012.

Total reserves increased 14% to approximately 1.2 Tcfe at 12/31, 48% liquids with a PV10 of $1.7 million. And 3P reserves increased to over 3.6 Tcfe for the company, a 70% increase over 2011.

In the Wattenberg Field, we expensed continued success with the horizontal Niobrara drilling program and narrow our experiencing success with the horizontal Codell wells and downspacing initiatives. Bart will discuss the activity in the Wattenberg in more detail shortly.

In the second -- on the fourth quarter -- no, in the second quarter of 2012, we acquired over 30,000 additional acreage and related production in the core Wattenberg Field. In 2012, we completed the acquisition of approximately 45,000 net acres in the Utica play in Southeast Ohio for approximately $2,000 per acre. This is an excellent entry point from a cost per acre standpoint compared to recent transactions. We believe the Utica play has the potential to be a world-class shale development, and Bart will discuss further and give some insights into our recent well tests in the Utica, which we announced this morning.

At present, we have 4 rigs drilling all horizontal wells, 2 in the Niobrara play, 1 in the Utica and 1 in the Marcellus. We continue to focus on maintaining a strong balance sheet and have announced several initiatives over the last year that will fund a 2013 development program.

The company announced the divestiture of our Permian Basin position for a total of $189 million in the first quarter of 2012. The company closed an equity offering in May for 6.5 million shares or about $165 million. In October, we completed a private placement of $500 million of 7 3/4% senior notes due in 2022. As part of our semiannual redetermination process and adjusting for the high-yield placement, the revolving credit facility with our bank was increased to $450 million. We exited the year with $399 million of available liquidity on a consolidated basis.

And most recently, we announced the sale of a non-core Colorado natural gas assets for $200 million.

So to summarize, PDC had an excellent year in 2012, both financially and operationally. We continue to focus on adding value for our shareholders and expect to be in an excellent position to execute our 2013 capital program and business plan, focusing on 3 high-quality horizontal plays.

I will now turn the call over to Gysle for his financial review. Gysle?

Gysle R. Shellum

Thanks, Jim, and good morning, everyone. As always, my comments will be high level, so for a more complete analysis of our fourth quarter and full year, please see our press release and the 10-K that we filed earlier today. I will also provide some preliminary guidance for 2013 based on our previously announced capital plan and production, adjusting for the pending sale of Piceance and NECO assets.

I would summarize 2012 as a transitional year for PDC. We had a lot going on during the year in acquisitions and divestitures, as well as capital markets. Our fourth quarter and full year results from continuing operations, as reported, reflect the impact of several events we undertook to reposition the company to a more liquids-rich inventory and production stream. Jim touched on some of the more significant items in 2012 including the impairment of our Piceance properties resulting from the pending sale of our Colorado dry assets. This agreement resulted in an after-tax impairment of about $100 million in the fourth quarter.

We also expensed 4 exploratory wells in our current quarter for about $9 million after-tax, and we incurred costs of about $14 million after-tax related to the early extinguishment of debt and the refinancing of our high-yield bonds in -- the fourth quarter 2012. Add all that up and you get about $123 million of after-tax charges related to nonrecurring events.

As previously announced, production for the year was slightly below our 2012 midyear guidance. I will talk more about that in a minute. As far as financial results, we hit the high end of our mid year guidance for adjusted cash flow from operations, and we're in the middle of the range for adjusted EBITDA. Adjusted net income is a challenge to sort out through the events I just mentioned. And we would have been within our midyear guidance range if those events were moved. I'll come back to that in a minute.

That's the high-level summary. Let's take a look at some of the metrics for the fourth quarter and the full year 2012. On Slide 7, sales from continuing operations for both the fourth quarter and the full year of 2012 were pretty close to flat, coming in slightly below same periods last year. The culprit was pricing. Average prices for all commodities were lower in 2012 than they were in the previous year. Natural gas prices were down 33% for the full year compared to last year's NGLs -- compared to last year, and NGLs were also down 28% for the year. Crude oil was down an average of 1% during the year. These price differences offset the 10% increase in production year-over-year, resulting in a 2% decrease in oil and gas sales before realized hedge gains in 2012.

Realized hedging gains were a little over $49 million for the year compared to about $17 million for 2011. The story is pretty much the same for the fourth quarter, natural gas prices were down 2% while NGLs were down 17% compared to the fourth quarter of 2011, and crude oil prices declined about 5%. Production increased 2% to 13 Bcfe during the fourth quarter 2012 compared to the fourth quarter 2011. As a result, oil and gas sales before realized hedge gains in the current quarter were a couple million dollars less than the fourth quarter last year. Realized gains of $10 million in the fourth quarter 2012 compared to $4 million in the fourth quarter last year more than made up the slight decrease in sales between quarters.

Production costs from continuing operations didn't move much on a per unit measure. Production cost include lifting cost, taxes and overhead. For the full year 2012, we averaged $1.52 per Mcfe, which is 2% higher than -- $0.02 than last year. The fourth quarter 2012, we averaged $1.41, which is 8% lower than the fourth quarter last year. Bart will talk more about the lifting cost component which decreased year-over-year on a per unit basis.

Overhead cost contributed to the full year increase in production cost per unit in 2012. Production overhead was $8.5 million higher in 2012 due to several nonrecurring events impacting both years.

Margins were 72% of sales for the full year of 2012 compared to 76% in 2011, reflecting the decline in average prices in 2012, again before realized hedge gains. Fourth quarter margins were about flat at 76% in 2012 compared to last year's fourth quarter margins.

Average gas prices increased in the quarter and more liquids were produced as a percent of total production, which impacted the fourth quarter increase over the full year margins. Adjusted cash flow from operations is defined as cash flow from operations excluding changes in working capital. The trend here reflects the same trend in oil and gas sales and gross margin for the periods presented.

Adjusted EBITDA in the current quarter and the full year 2012 was impacted by higher exploratory dry hole costs of about $15 million pre tax compared to the fourth quarter and full year 2012.

I mentioned the after-tax cost earlier in my opening comments. Realized hedge gains are included in these numbers and adjusted cash flow numbers as well.

Adjusted EBITDA per diluted share reflects the issuance of shares in the second quarter 2012, which was a weighted average increase of about 4.1 million shares for 2012 compared to 2011, and an increase of about 6.2 million shares in the fourth quarter 2012 compared to the fourth quarter 2011.

DD&A includes depreciation of fixed assets and depletion of oil and gas properties. The increase in 2012 compared to 2011 was due primarily to the increase in production, as well as a slight increase in the DD&A rates. Per unit depletion rates on oil and gas properties for the fourth quarter and year ended 2012 were $2.94 and $2.81, respectively compared to $2.81 and $2.74 for the fourth quarter and year ended 2011.

G&A decreased in 2012 compared to 2011 mostly because of nonrecurring charges in 2011 related to an employee separation agreement and settlement of a lawsuit.

[indiscernible] to this next slide reflects results attributable to shareholders for the quarter and year end for Generally Accepted Accounting Principles, which includes unrealized gains and losses of mark-to-market hedge positions. All the events I mentioned in my opening comments are included here, as well as discontinued operations from the Permian properties.

Up next, the page shows adjusted net income and earnings per share with unrealized hedge gains and losses removed that includes $123 million cumulative after-tax impact of the Piceance impairment, exploration dry hole expense and the charge for early extinguishment of debt in the fourth quarter 2012. We have left these nonrecurring cost in the table to be consistent with our prior presentations.

Adjusted for these costs, we would have reported a net income of approximately $3 million for the year ended 2012, which was in the lower half of our full year guidance range.

PDC's revolver borrowing base of $450 million is scheduled for redetermination in May 2013 and is expected to occur after the sale of Piceance and NECO assets close. We recently began discussions with our banks on the redetermination process, so we don't know at this point what impact, if any, that sale had on our borrowing base. Proceeds from the sale and expected cash flow from 2013 operations should easily carry us in 2014 with adequate liquidity.

The table on this page reflects PDC's borrowings. Our financial statements include our proportionate share of the Marcellus joint venture debt as well, which was $26 million drawn at year end. So combined, we reported revolver debt of $75 million. The joint venture is nonrecourse to PDC and doesn't count against PDC's $450 million borrowing base.

Most of you know, and Jim mentioned earlier, that we refinanced our high-yield debt in the fourth quarter 2012, and that $500 million issue matures on October 2012.

Next slide shows our hedge positions for 2013, 2014 and 2015 and excludes the hedges to be part of the pending sale of Piceance and NECO assets for the 3 years presented. We have hedged substantially all of the oil and gas production we are allowed to hedge under the terms of our credit agreement for 2013. For 2014, about 50% of our allowable production is hedged after we stripped out hedges related to the pending sale. We're working on adding to our 2014 and 2015 positions and have layered some hedges in since the end of the year last year and we'll report to the market in early April.

You can see here that gas hedges are substantially all swaps and oil is largely collars. We still think there is more downside risk than upside opportunity in gas prices. We're not that bearish on oil.

Hedge positions won't tie back to the 10-K we filed this morning as that document includes the positions that are going to be part of the pending sale of Piceance and NECO assets.

Let's look at our quarterly realized hedge prices. The takeaway here is that we ended the year slightly above our expected average realized price per Mcfe for the year based on our midyear price guidance.

My last slide here looks at a preliminary 2013 financial guidance. We provided the market with guidance for capital expenditures and production earlier this year. That guidance included production for the full year of 2013 from Piceance and NECO. Presentation of the financial guidance you see here excludes Piceance and NECO production and related costs as the pending sale of these properties is effective January 1, 2013. Piceance and NECO are expected to be presented as discontinued operations in the beginning of the first quarter of 2013. Bart will update you on the adjustment to our capital program related to the sale.

We reduced our previously announced production forecast for 2013 by 13 Bcfe for the full year. This guidance is based on a range of about 43 Bcfe or about 7.1 million barrels of oil equivalent production for the year. That compares to about 33 Bcfe or about 5.5 million barrels of oil equivalent on pro forma continuing operations in 2012.

Much of the results from our 2013 capital program are back-end loaded due to our shift to pad drilling in Wattenberg and the resulting lags between turnaround times, also timing of the addition of the third rig in Wattenberg in the third quarter and timing of midstream solutions in both Wattenberg and Utica. We will be providing more data on operations and liquidity for 2013 at our Analyst Day in early April and we plan to also provide a peek in expectations for 2014 at that time.

With that, I'll turn this over to Bart for a discussion of our operations.

Barton R. Brookman

Thank you, Gysle, and hello, everyone. 2012 production for the company totaled 49.6 Bcf equivalent, slightly off our expectations, primarily due to the midstream constraints in the Wattenberg Field, but still 10% improvement from 2011 levels. We're very pleased 53% of the company's production came from the liquid-rich Wattenberg Field where we have ongoing horizontal drilling in both the Niobrara and the Codell formations. For the year, I should note, the company grew liquid production 18% from prior year levels.

From the map, the company -- you could see production for each operating basin, the Wattenberg Field had 26.7 Bcf equivalent, followed by Piceance at 13.5 Bcf, Appalachia Basin at 6.2 Bcf and NECO at 3.2 Bcf.

The company's extremely pleased with the reserve growth, the 1,157 Bcf equivalent or a 14% growth rate in our proved reserves. The PV10 of our reserve base jumped to $1.7 billion, a 27% improvement from prior year levels. This is primarily due to the booking of the liquid-rich horizontal projects in the Wattenberg Field.

Let me walk through the movement of our reserves as represented in the waterfall graph. Starting 2012, we had 1,016 Bcf equivalent. We divested 65 Bcfe, primarily the Permian, produced 50 Bcf and had a net improvement in our operating regions of 56 Bcf. Let me see if I can explain this 56 Bcfe number.

The impacts of extremely low gas prices and the removal of all the PUDs in the Piceance basin were more than offset by the horizontal additions in the Wattenberg Field and the horizontal bookings in the Marcellus. Again, net positive of all those forces is a positive 56 Bcf.

We acquired 200 Bcfes in the Wattenberg last summer, closing the year at 1,157 Bcf, again a 14% growth rate. When we adjust this for the upcoming sale of the Piceance and NECO of approximately 85 Bcfes, we see a pro forma of 1,072 Bcfes equivalent.

Some production highlights for the quarter. Fourth quarter productions saw a rebound in our overall production. Our liquid production in particular jumped 21% from third quarter levels. This is primarily a result of the contribution of the second rig in the Wattenberg Field and what we would classify as modest improvements in line pressure in this field as we continue to wait for major facility expansions from our primary gatherer.

In the quarter, we announced our Onega well in Ohio, which IP-ed at just under 1,800 barrels of oil equivalent per day. This is the company's first horizontal Utica well in eastern Ohio. Also, in the quarter, we turned on a 3 well Marcellus pad from the late 2011, early 2000 drilling. The initial rate on the 3-well pad was 19 million cubic feet per day. The bar graph shown shows the company's track record of production growth year after year, and you can see our 2013 guidance, that Gysle touched on, originally 55 to 57 Bcf equivalent, but also represented in this is the sale of the Piceance and the NECO assets.

The Utica overview. The next slide will give an update where we stand on the Utica project in eastern Ohio. You can see the Onega Commissioner well, which we announced mid-December at the 1,800 barrels of oil equivalent per day, that's 79% liquid mix. Today, we're very pleased to announce that Detweiler 42-3H, an IP of 2,197 barrels of oil equivalent per day. This was on a smaller -- the test was conducted on a smaller choke at 20/64s. With being just 4 miles east of the Onega well, we showed a liquid mix of 75% on this well.

Currently, we are drilling on the Stiers 3-well pad and we anticipate completing these 3 wells -- to completing the drilling on these 3 wells sometime in April. At that time, we will move to the Garvin 1H in the southern part of PDC's acreage at the very northern portion of Washington County. Again, the spud on that well is planned in April. Following the Garvin, we will drill the Maxwell well just to the west. Those will be the first 5 wells for the Utica project in 2013 and we will update you on more capital plans in this area at Analyst Day in early April.

Production by area. The next slide is an overview of the production by region, again covered on the first slide on the map, that Wattenberg is our biggest operating area and largest producer for the company, followed by Piceance, Appalachia and NECO, again for a total of 49.6 Bcf. For the year, the company produced 35% liquids. We fully expect this liquid mix to exceed 50% in 2013 after we execute on the sale of the Piceance and the NECO assets.

Update on our drilling activity in 2012. Throughout the year, our operating teams executed on our drilling activity very close to our operating plan as shown in the bar graph. For the year, we spud 42 horizontal operated wells. A breakdown of this drilling: 37 horizontals in the Wattenberg Field, 2 the Utica and 3 in the Marcellus. The company also executed 160 refrac recompletions for the year and participated in 19 non-operated projects, primarily in the Wattenberg Field.

Early guidance for 2013 was to spud 82 wells and execute 50 refrac recompletions for the company. The spud count will get updated at Analyst Day in early April.

The current drilling activity for the company is 2 horizontal rigs in the Wattenberg Field, 1 horizontal rig in the Utica and 1 horizontal rig in the Marcellus.

Next slide provides an update around the midstream expansions currently underway in the Wattenberg Field. The map shows PDC's acreage with major plants, compressor stations and pipelines under construction, which will all accommodate additional volumes in the Wattenberg Field. Important to note that the 4 compressor stations in green should provide dramatically reduced buying pressures. The LaSalle and Lucerne plants will both provide major increases in processing capacity within the field and then the FREX NGL pipeline will provide NGL transport -- additional NGL transport out of the basin. Please note how the facility expansions on this map strategically fit with PDC's acreage.

An update on the scheduling of some of these major projects. Several of the field compressor station should be up and running this summer, providing lower line pressures. The LaSalle plant is scheduled for an August 2013 start up and the FREX NDL pipeline is scheduled for a late 2013, early 2014 start up.

An update on our Wattenberg horizontal drilling program. The company is now reporting 40 horizontal Niobrara wells and 7 horizontals Codell wells. Both programs continue to deliver outstanding results. You can see the performance of our horizontal Codell program, which is performing, right now, better than our overall Niobrara program. Again, there are 7 wells in this Codell average. In our Niobrara program -- our Niobrara continues to perform in line with prior reported averages of 340,000 barrels equivalent per well of reserves.

In 2013, expect the Wattenberg drilling to be approximately 50% Codell, 40% Niobrara B and 10% Niobrara C bench.

A quick overview of the company's capital program for 2012. $184 million was spent on developmental drilling, primarily the Wattenberg Field. $113 million was spent on leasehold and exploration, primarily the Utica project. $304 million on the Wattenberg acquisition last summer, and this number is after some post closing adjustments. For a total of $602 million on development, exploration and acquisitions in 2012.

In 2013, we anticipate $317 million in capital expenditures, the bulk of that on development projects. And we will be updating this $317 million estimate for 2013 at our Analyst Day in April after we finalize our adjusted capital plans.

Lease operating expenses. They continued to improve in 2012. Overall, lifting cost or $0.85 per Mcf, this is a $0.07 reduction from 2011 levels. We specifically saw improvement in our work over, execution and management in all districts, and ongoing improvements in our water management efforts, particularly in the Piceance Basin.

These, coupled with production gains, resulted in an improvement in this overall unit measurement. You should also note that the $0.85 per Mcf include the costs we incurred in the second half of the year related to the Wattenberg acquisition. Some of these costs were higher than normal to bring those properties up to PDC's operating standards.

So in closing, just some highlights. Wattenberg, we couldn't be more pleased with our horizontal drilling program. We achieved a production of 5,000 Boe per day, directly related to this horizontal programs in the fourth quarter. For the year, we drilled the 28 horizontal Niobraras and the 9 horizontal Codells. As shown in the prior type curves, our horizontal Codell program right now are performing at or above our horizontal Niobraras. Our cost structure remains at $4.2 million per well and that's for both the Codell wells and the Niobrara wells. We have 5 downspaced pads that have been completed and are online, and I would classify them as very encouraging results. Currently, we are producing well bores from the Niobrara A bench, B bench and C bench. Our reserves continue to fall within the 300,000 to 500,000-barrel per well range. Currently we are still drilling in the 70% to 80% liquid-rich portion of the field. And the third-party midstream expansions are on schedule and should dramatically improve our production levels as we go through the second half of the year.

In the Utica, we've secured our 45,000 acres. Most of our acreage is in the liquid-rich window. Our first well, the Onega, had an IP of 1,800 Boe per day. And today, we were happy to announce the Detweiler, just under 2,200 barrels of oil equivalent per day.

Currently, we're drilling a 3-well pad in Southern Guernsey County, and by mid-summer, we would have delineated Northern Washington County. We have multiple midstream options, both for gathering and process that we are finalizing the terms on.

And in the Marcellus, we're happy to be back to drilling in Harrison County. We turned on the 3-well pad in the fourth quarter at 19 million a day, and in the fourth quarter, our operating teams did an excellent job in overall shallow Devonian production levels.

With that, I'm going to turn this back to the operator for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from John Malone of Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Just, Bart, a question talking about the 5 downspaced pads you've had. You said encouraging results. Is that downspacing to the 11 net wells that you've highlighted in the past? And can you give some sense as to how many acres in the Wattenberg you could bring to that 11 net wells per section?

Barton R. Brookman

All 5 of the downspaced pads are approximately the 11 or 12 wells -- 11 net wells, 12 gross wells equivalent per pad. A little bit different pattern on each one, but total well count right in line with what you're asking.

John Malone - Global Hunter Securities, LLC, Research Division

Okay, great. And then just to go over to Utica for a second, looking to drill a lot of well -- another well that is a little bit below the 4,000 foot lateral. Is that a lease line issue? And if it was, is there something you guys are working on to try to drill longer laterals to kind of pool acreage in the area?

Barton R. Brookman

First part of the question, yes. It was a lease line. Second, yes also. We're working -- our line group's diligently working to pool acreage. The Stiers pad, I believe, is closer to 5,000-foot laterals and the operating team right now really has a 5,000 to 6,000-foot goal for lateral length. If we have acreage that's conducive to a 7,000, we would, of course, try that also. Right now, though, expect probably that 5,000 to 6,000 foot.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And then just assuming the continuity of acreage you got in the South, that's where you're thinking you can do 5,000, 6,000 maybe longer there?

Barton R. Brookman

That is correct.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. Just last one for me. You talked about sales of production for the year being 50% or greater than 50% liquids. Pro forma, the Colorado sale, is that back ended or do you think in Q1 you could be there, greater than 50%?

Barton R. Brookman

Adjusted for -- you know what...

James M. Trimble

Adjusted for continuous operations, we'll be at that 50% or slightly higher starting in the first quarter.

Operator

Our next question comes from Ryan Oatman of SunTrust.

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

A very nice job with this second Utica well. I do want to shift back to the first though, the Onega. You guys recently disclosed that you've been producing condensate from that well since mid-January, collecting production data and evaluating performance. Are there any results or color you can share from that testing?

Barton R. Brookman

We will share that at Analyst Day.

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

Okay, fair enough. And then a little bit of allusion in terms of Utica infrastructure. Can you speak to where you are with that Utica infrastructure and then where specifically you guys are on this next 3-well pad at this point? And then a follow on, do you see a good potential to add $50 million or so to the capital program at the second half of the year based on the results that you're seeing so far?

James M. Trimble

Well, I'll start off by just saying, what we're doing right now is evaluating the entire capital program that we have planned, and specifically as we take into account the divestitures that we're taking and looking at. So we're going through that right now. We'll be discussing that at the Analyst Day. We will have a complete new presentation of production and capital program. And then, we're working very hard to get the midstream and I'll let Lance, who's been more driving that, kind of give you a flavor of that.

Lance A. Lauck

Yes, Ryan. So where we are with the midstream side, we're basically working on the final details with the midstream provider in the northern area there. And we've got the basic framework put together with that. So we are moving forward with getting that finalized and look for first production with that in the second quarter of 2013.

Operator

Our next question comes from Mike Scialla of Stifel.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

You talked about Codell and showed the evidence of that outperforming the Niobrara some. Can you talk about what you think is going on there? I mean, my understanding is Niobrara's a lot thicker reservoir. Does that suggest you're getting some contribution from the Niobrara in the Codell wells? Or just what do you think is happening there?

Barton R. Brookman

Yes, I think, Mike, you're probably spot on. We clearly are getting some contribution from other areas when you do your in-place reserves. What we also think is happening is Codell's obviously a more permeable rock. So we've got a better near-wellbore conductivity. So we're just seeing better sustained pressures and it's slightly deeper. So we have better pressures, better conductivity in the rock and obviously, some contributions coming from some other areas. But we couldn't be more pleased overall, particularly the fact that we're in the very northern portion of the Wattenberg Field where vertical Codell economics have been very challenging for the history of this space, and then we're getting tremendous results on a horizontal basis.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

If I go back to a previous question about the downspaced pads. I know you've tried a few different configurations. Does that maybe argue for the alternate kind of where you land in the lateral, I guess, in terms of how you ultimately develop this if you're going to downspace to something on the order of 12 gross wells per section?

Barton R. Brookman

Yes, in -- we're going to give a lot more detail around the patterns and the downspacing at Analyst Day. But we absolutely are learning not only from our peers, but also our in-house tests, what we think is best. So there's definitely some things that we'll communicate to you guys.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then switching over to the Utica. I think you've acquired a few more industry data points from maybe some of your own from your southern acreage. Can you just talk in general about how you feel about that acreage now? How it compares to your northern acreage in terms of geology and based on the data that you have at this point?

Barton R. Brookman

Well, we've got -- the additional data points, I believe there's 1 well north of us that provides additional support and we've gotten 1 core data point just to the east of our southern acreage. All of it, as we've said all along, continues to support that the southern acreage from the basic rock properties we're looking for. We are extremely excited about this first well, the Garvin, and the second well, the Maxwell. So right now, everything we have points towards this being very, very prospective for horizontal drilling. And there are some points that have also confirmed permeability. And I probably won't mention the operator, but there's a well just east of our acreage in Monroe County that had a substantial dry gas rate. So as you move south, there's some factors that the permeability is also maintained, which is very important in this play.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Anything you can say about the reservoir pressures between the 2 different areas?

Barton R. Brookman

Not at this time.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just one last one, I guess, philosophical. You obviously have some great assets. Your balance sheet, even after the sale, maybe still a little bit more debt heavy than you may want. Would you consider going back to the market with the Utica at this point, maybe even just for the southern acreage? Or is that kind of off the table now given the results you've seen?

James M. Trimble

It's off the table now from what we've seen and the results that we're expecting. We might have a little more debt on the books than we would like. But liquidity-wise, we're very strong. We've got -- we believe we're in very strong results. And so I think that we're happy where we are.

Operator

Our next question comes from Irene Haas of Wunderlich Securities.

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

Maybe a quick question on the Utica. In the midstream, do you have a feel as to where your products going to end up in terms of your condensate liquids and gas? Are they going to sort of stick around the local area or would they come to the Gulf Coast, specifically on the liquid end? Then also a question on Marcellus, how is it looking? At current pricing, how the margin's pulling out?

Lance A. Lauck

Okay, Irene, it's Lance. I'll talk about the marketing side for this. The gas from Utica will be sold there in the Appalachia region areas, [indiscernible] most likely. The condensate itself is sold locally, it's trucked off a location and sold to local refineries there. So that's utilized there in the local market. And then the NGLs themselves, we expect them to stay, for the most part, local as well, with the various propanes and butanes that are a key part of the NGL stream here in the area. So from where we sit today, that's kind of the overall look at where we see the products coming from the Utica.

Barton R. Brookman

And on the Marcellus, Irene, again, we just, in the last several weeks, initiated drilling there. We are in Harrison County. We are in the area where we've achieved the best reserves, we're in the 7 to 9 Bcf per well target range. We're going with longer laterals. And right now, with current strip pricing, we're in that 30% internal rate of return type returns on drilling.

Operator

Our next question comes from Welles Fitzpatrick of Johnson Rice.

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

Are you guys still expecting that additional Wattenberg rig in early on the third quarter? I saw CapEx drop a touch.

James M. Trimble

Well, the drop of the CapEx was because we took out the properties we're selling and the capital that was associated with those. We haven't given the new guidance on capital yet. We will do that at Analyst Day and we will talk about when the rig will be coming. But right now it still is as we projected to you earlier, was in midyear.

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

Perfect. And you guys have talked about potentially adding some CapEx up in the Utica and bringing that idea to the Board. Has that happened yet? And if not, when should we expect an update on it?

James M. Trimble

The Board meeting, we will be giving is in March for our Board of Directors, and that we will then bring all that information to the Analyst Day with the new guidance.

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

Okay, perfect. And then on the Garvin, it looks like that's maybe 5 miles east of the Palmer. If I'm remembering correctly, it's either the Palmer or some other publicly available core that had a vitrinite reflectance of something in the 1.4, 1.5 range kind of at the top end of the white gas window range. Is that accurate? And what kind of GOR should we be expecting there?

Barton R. Brookman

On the reflectance number, I'd have to go get my geological data in front of me, Welles, to even comment on that. And that's something we'll probably be covering in early April because we're going to try to give a really good snapshot of the geologic properties in our southern acreage. In the GOR, the depth we're anticipating, I believe, we are slightly deeper subsurface than the Detweiler well. I want to say 300 or 400-foot deeper. So again, we do have some belief that there's a correlation of depth to GOR. So I would expect probably, maybe 70% to 75% liquid mix, but we won't know until we get there and drill the well.

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

Okay, perfect. And just one point of clarity for me and I think you guys have said this before, so I apologize. But the IRRs on Slide 22, the 123% IRR, that is based off of a Niobrara GOR as opposed to Codell. So if the Codell hit that 500, theoretically it would be higher, is that right?

James M. Trimble

Those are based off of the Niobrara wells. And the Codell and the Niobrara are very similar. I mean, there's not a lot of difference. So it might be slightly better, but I think I would say, for the type numbers we're looking at there, whether it's 123% or greater, it's still a pretty good number.

Operator

Our next question comes from David Tameron, Wells Fargo.

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

Congrats on getting that Piceance asset sold.

James M. Trimble

Thanks, David.

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

The Codell -- and I know Mike asked the question about the Codell, good contributions, et cetera. But is there -- can you give us any more color? Do you think the Codell is present across x percent of your acreage? Can you just give some -- I know we've talked about it in the past, but can you remind me what -- how you think, just in general terms, about the Codell?

Barton R. Brookman

Yes, well the Codell blanket across the core of Wattenberg, and again it was the primary zone targeted from a vertical program. The Niobrara's overshadowed it here the last couple of years. But it is almost 100% present on our current acreage position, which is updated for the post-closing adjustments for the last summer's Wattenberg acquisition and net of the Krieger which is -- which we're transacting on. So I think we're 95,000 acres right now. And David, I would say -- almost 100,000 acres in the Wattenberg Field. We're probably 98% of that where we have Codell. And the really encouraging thing that's going on is some of these Codell wells are in the very northern portion of our acreage position, like I said, where vertical drilling over the years has been less attractive in the Codell formation, but we're achieving very, very strong results on a horizontal basis. Hopefully, I answered your question.

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

Yes. No, it's helpful. And then are you guys seeing any differences between the A, B and C as far as the benches in the Niobrara as far as productivity?

Barton R. Brookman

Yes. And obviously the curves that we presented, the average on the 40 wells, the bulk of that is B. On a general sense, I can tell you we're really excited about the C. We're still driving value with the A. But as I said, our '13 program, in my comments, is going to be primarily B and C development.

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

All right, in the -- go ahead, Bart, I'm sorry.

Barton R. Brookman

We'll give a lot more detail on the A, B and C in early April.

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

Okay. And can you talk about recent line pressures obviously with the weather? And then what was the line pressure, but are you guys -- the colder weather, but are you experiencing any freeze off issues?

Barton R. Brookman

Second part, yes. We always have freezing as we go through. So we have some impacts to our production. Line pressures in the fourth quarter improved from second and third quarter levels but are not back to what we could call historical levels. So there's still some progress to be made here. We still, in the fourth quarter, have some constrained gas and oil production. January, just a flavor, was a good month. DCP had good one times, and overall, operating, they performed very well. So I know we have some scheduled downtime coming up. So in March, we may have a couple periods where the line pressures will be up a little bit. But overall, as we've gone through the winter, it has been -- as I classified it in my talk, modest improvements in line pressure.

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

Okay. And then final question, just on the production guidance for '13, it sounds like you lowered it by more than divestments, did I hear that right? And if so, can you give us any color on just that delta?

James M. Trimble

Well, I think when we put the press release out announcing we said it was 10 Bcf related, that was for the second, third and fourth quarter because we anticipate closing in the second quarter. But really, it's 13 Bcfs for the year because it's effective January 1, so we got to take out the entire year's production, not just the second and third and fourth quarter. And so, that, really, the difference there is all we did was take off the 13 Bcfs from the guidance we had given earlier.

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

Okay. So that 42, whatever that number was, that's the pro forma assuming that transaction closed January 1?

James M. Trimble

Correct.

Operator

Our next question comes from Joe Allman of JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Bart, how much HBP drilling are you doing this year in each area, first the Wattenberg and Utica, then the Marcellus?

Barton R. Brookman

Oh, boy. Joe, we have -- a few leases in Wattenberg were earning with, actually 1 or 2 of the rigs. And then, the balance of the second half of the year will be HBP. In '14, you'll see primarily HBP in Wattenberg. Utica, I don't know if I have that answer for you. About 55% of our acreage, I think, is HBP. And I think it's a blend. We have some drilling commitment acreage and we have some HBP that we're drilling in the Utica. And then the Marcellus, almost everything we're doing is HBP acreage.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. So just to clarify, so in the Wattenberg, I mean, most of your acreage is HBP. So this year's drilling, you're not drilling necessarily just to hold acreage, you're drilling just to delineate and to develop the play, I mean, is that correct, or...

James M. Trimble

That's correct, Joe. I'd say in all of our cases where we're drilling, it's really delineating and developing. Even in the Utica where we've got -- where we do have leases, we still have 5-year primary term with 5-year options. So we have plenty of time. So we're really drilling for maximizing returns.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. No, that's helpful. And then a question on the financials. So just, I know someone asked a question earlier about -- and Jim you mentioned you're comfortable with the debt. So any plans or any financial transactions in the next 12 months?

James M. Trimble

No. The only thing we've got is the divestiture that we're bringing in, the $200 million. And we don't have any other financial plans to raise capital.

Operator

Our next question comes from Adam Michael of Miller Tabak.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

I'd like to go back to the Codell. I mean, initial results are just really impressive. And I wanted to see if maybe you could elaborate a little more on the oil contribution and maybe the commodity mix you're seeing in those initial wells?

Barton R. Brookman

And again, most of our Codell development has been with the downspaced pads and has been very similar geographically where we're developing the Niobrara in the northeastern portion of the field. So the total liquid mix from the Codell right now is very similar in the Niobrara, that 70%, 80% total liquids, and the breakout is approximately 60% condensate, 15% NGLs and about 25% natural gas.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

And what percentage of the approximate 100,000 acres in the Wattenberg is above that 70% liquids line?

Barton R. Brookman

I don't have that number off the top of my head.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Okay. I guess, the other part that I have is have you guys looked at possibly drilling some extended reach laterals? And the reason I'm asking is I know some other operators are seeing even better rates of return on taking the horizontal lifts down a little bit further, I just wanted to kind of get your thoughts on that.

Barton R. Brookman

Yes, we have a -- we just initiated production on a 6,000-foot Codell. So we do have plans for some, call it modest extensions of the lateral. We don't have any plans right now for some -- what you have seen is some 8,000 and 9,000-foot laterals. But it is something we're keeping our eye on. Our acreage pattern isn't necessarily that conducive to 9,000-foot runs. But we are -- we do have some acreage blocks and this 6,000-foot makes sense. So we're going to continue to test that.

Operator

[Operator Instructions] Our next question comes from David Beard of Iberia.

David E. Beard - Iberia Capital Partners, Research Division

Just a couple of follow-ups as most of my questions have been answered. But you talked about Codell. Will you breakout a separate type curve? Do we have enough data? And would that be something for analyst meeting or later on in the year?

Barton R. Brookman

I think we'll give good flavor at Analyst Day around some individual well performances in the Codell. And absolutely, as we go through the year and gain more data, we will be developing individual Codell-type curves, probably for the 3 major areas that we've broken out, which is center, inner and outer core Wattenberg. So our reserve group will absolutely be developing type curves for that formation.

David E. Beard - Iberia Capital Partners, Research Division

Okay. And then just switching to the Utica. Would you be in a position to talk about either EURs for the Onega? Or how long would you like to flow these wells before you feel comfortable with an EUR estimate?

Barton R. Brookman

We have IPs and not even close to talking EURs yet.

David E. Beard - Iberia Capital Partners, Research Division

Okay. And then maybe you can talk a little bit about the second half plans for drilling in the Utica?

Barton R. Brookman

We'll cover all of that at Analyst Day. I updated everybody on the 5 wells that we have firm plans to drill. And again, any expansions in the capital in the Utica will be approved by our Board mid-March and announced to the market at Analyst Day.

Operator

Our next question comes from Jack Aydin of KeyBanc.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Do you care to give us the average 30-day rates for the Onega Commissioners or if there is 30-days, 60-days average production from that well?

James M. Trimble

Jack, we've only just started flow testing and been doing some work over there. We'll have more data -- we started in January, and we've just been -- so we'll have data at the Analyst Day, which we will be giving. We'll give out all the detailed stuff we have at that time. It's just a little early for us at this point.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Second question I have, I know you touched on it, but you mentioned that you're going to spend your capital, 50% Codell, 40% B bench and 10% C. Are you giving up on the A? And what is the philosophy of not doing anything on the A in 2013? Could you elaborate a little bit?

Barton R. Brookman

We're not giving up on the A. But based on the data that we have and our operating team's recommendation, our best allocation of capital is to target the B and the C bench. And Jack, we'll cover some of this at Analyst Day. Obviously, there are reserves in the A. We don't feel like we're leaving anything behind here. And this comes down to the optimum downspacing of the laterals in the Niobrara. So right now, we feel like the B and the C is the best allocation of our capital within that zone.

Operator

Our next question comes from Mo Dahhane of Wunderlich Securities.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

I'm just curious, do you guys any plans to do any extended lateral horizontals in the Wattenberg? I know Nobel is doing it and Bonanza, and it seems like they have better economics than regular lateral horizontals.

Barton R. Brookman

Yes. And as I noted, we currently have -- actually this week, initial production on a 6,000-foot Codell. We have plans for additional, call it 6,000-foot type laterals in our operating plans. But we don't currently have anything in the 8,000 to 9,000-foot length range. Some of that is driven by how our acreage -- the pattern of our acreage and being able to make that long number run.

Operator

Our next question comes from Brian Kuzma of Weiss Multi-Strategy.

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

I wanted to follow up on the -- you were talking about how much the Codell has been derisked and the fact that you think you have it on 100% of your acreage. I wanted to make sure how much of that acreage you think has been developed vertically?

James M. Trimble

The Codell was the primary development out here for 20 years. And so as I recall, there's like 13,000 wells drilled across the basin in the Codell. So there's a tremendous amount of data available as far as the reservoir. And so as Bart said, about 98% of our acreage has the Codell because you can -- even though it's probably some of the acreage has been drilled that are much more dense than other. But I think what you're looking is that we feel very confident in the numbers and for the -- that we've talked about. So just from all the vertical wells that have been drilled out here.

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

And so the location counts that you guys have put together for the Codell, those are engineered locations in terms of you won't get drainage?

James M. Trimble

Right. They're put on the map with the whole development team, the engineers, geologists. Everybody sitting together and spotting and laying out the locations. So it's not a just divide acreage by well count is, it's actually dots on the map.

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

Got you. Okay. And then as I look at these Codell type curves and the fact that the decline curve looks so shallow over the first 180 days, is the wells restricted initially? Or what do you think they'd be capable of if they weren't restricted, I guess? Any kind of color there on the shape of that curve?

Barton R. Brookman

No. And again we flow -- we're producing these wells with that pressure on the well which is -- and the northern area is more conducive to making sure we can buck line pressure most importantly. But also we seem to be getting a better clean up pattern on both the Niobrara and the Codell, Brian. So yes, we are holding some back pressure on those. The slope of the curve, I think, as -- go back to Mike's question, is probably more conducive or reflective of quality of the reservoir rock, the permeability in some of the pressures that we're seeing and the effectiveness in how the Codell fracs versus how the Niobrara fracs. So you have a different animal here. But the net-net right now is we're very pleased with the overall performance of those wells.

Operator

With that, I'd now like to turn the conference back over to Mr. Trimble for any closing remarks.

James M. Trimble

Well, thank you. And I'd like to just say thanks everyone for dialing in and participating this morning. Have a great day.

Operator

Ladies and gentlemen, this does conclude today's conference. You may all disconnect and have a wonderful day.

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