PDC Energy, Inc.
Q4 2013 Earnings Call Transcript

Published: 20 Feb 2014

[Operator:]

Greetings and welcome to PDC Energy 2013 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, President of PDC Energy. Joining Mr. Trimble on the call is Mr. Barton Brookman, Executive Vice President and Chief Operating Officer; Mr. Gysle Shellum, Chief Financial Officer, and Mr. Lance Lauck, Senior Vice President, Corporate Development. It is now my pleasure to introduce your host, Mr. James Trimble. Mr. Trimble, you may begin.

[James M. Trimble:]

Thank you, Kevin. Good morning, and thank you for joining us today to discuss PDC's fourth quarter and year-end 2013 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 high-level highlights for the year, followed by Gysle on financials, and then Bart on operations, both of whom will go into greater detail. At the beginning of 2013, our stated strategy was to focus our efforts on the development and exportation of our core assets in the Wattenberg Field and the Utica and Marcellus shales. Embedded in that strategy was to accomplish several goals

[Gysle R. Shellum:]

Thanks, Jim, and good morning, everyone. Thanks for joining us today. As always, my comments will be high level. So for a more complete analysis of our fourth quarter and full year 2013, please see our press release that was filed this morning and our 10-K, which will be filed after market close today. I'll also provide some preliminary financial guidance for 2014 based on our previously announced capital plan and production. I would summarize 2013 as a year where PDC focused on liquids production. It was another active year, with divestitures of more than 4,000 dry gas wells that helped fund capital programs in our Wattenberg and Utica Shale plays. Our fourth quarter reflects the impact of both programs, with record crude oil production from PDC and Wattenberg and a gross exit volume of over 5,000 barrels of oil equivalent per day from the Utica. As Jim mentioned, production for 2013 was 7.4 million barrels of oil equivalent, above the midpoint of our guidance. There were a few late-reporting, non-operated wells in Wattenberg that improved our production number for the year from the 7.3 million Boe we previously announced. Bart will cover that in greater detail in a few minutes. As for financial results, we beat the high end of our annual guidance for adjusted cash flow from operations and were near the high end of our range for adjusted EBITDA. Adjusted net income includes the impairment on joint venture shallow gas properties that impacted net income by $28.9 million net to PDC. Without the impairment, we would've been within our range of guidance for net income, as well. That's the high-level summary. Now let's get into some of the metrics for the fourth quarter and the full year. Dry gas sales from continuing operations for the fourth quarter took a big stair step along with liquids production, which is what we forecasted back in April. Fourth quarter and full year 2013 sales were up considerably from the same periods last year. While pricing played a role, our activity in Wattenberg was the largest contributor. Average prices for all commodities were higher in 2013 than they were in the previous year. Natural gas prices were up 25% for the full year compared to last year, and NGLs were up about 2% for the year. Crude oil prices were up an average of 3% during the year. These price increases, coupled with the 35% increase in production year-over-year, resulted in a 51% increase in oil and gas sales before we [indiscernible] realized hedge gains in 2013. Realized hedging gains, which we now call net settlements on derivatives in our filed documents, were about $13 million in 2013 compared to about $49 million in 2012. The story for the fourth quarter was strong production growth and fairly stable commodity prices that led to a large jump in sales compared to the third quarter 2013, as well as the fourth quarter of 2012. Natural gas prices were flat while NGL prices were up 2% over the same quarter of 2012, and crude oil prices were up about 7%. Production increased 58% to 2.4 million Boe during the fourth quarter 2013, compared to the fourth quarter of 2012. As a result, oil and gas sales before realized hedge gains in the current quarter were up 70% -- 77% over the fourth quarter last year. Realized hedge losses of $2.6 million in the fourth quarter 2013, compared to the gain of $14 million in the fourth quarter last year. Production costs from continuing operations on a per unit measure moved up about 4% quarter-over-quarter. Production costs include lifting cost, taxes and overhead. For the full year 2013, we averaged $9.88 per barrel of oil equivalent, $0.08 lower than last year. For the fourth quarter of 2013, we averaged $9.28 per Boe, $0.34 higher than the same quarter last year. The fourth quarter increase is due primarily to flood-related costs, increased labor costs and environmental compliance costs. Bart will talk a little bit more about the lifting cost part of production costs, which were flat year-over-year on a per unit basis. Overhead costs decreased 11% quarter-over-quarter and were down 4% for the full year of 2013 compared to 2012. Gross margins were 80% of sales for the year ended 2013, compared to 77% for 2012, reflecting the increase in average prices in 2013, again, before realized hedge gains, as well as an increase in liquids production as a percent of total production in 2013. Fourth quarter margins were about flat at 81% in 2013 compared to the fourth quarter last year. The next 3 metrics on this slide are non-GAAP metrics, which are reconciled to GAAP in the appendix of this presentation. Adjusted cash flow from operations is defined as cash flow from operations, excluding charges -- changes in working capital. The upward trend here reflects the production volume growth, which pushed oil and gas sales higher for the period presented. Adjusted EBITDA in the current quarter was up over 100% compared to the fourth quarter of 2012. And the full year 2013 was up 22% compared to full year 2012. Adjusted EBITDA per diluted share reflects the issuance of shares in the third quarter of 2013, which was a weighted average increase of 4.7 million shares for 2013 compared to 2012, an increase of 6.6 million shares in the fourth quarter of 2013 compared to the fourth quarter of 2012. DD&A includes depreciation from fixed assets and depletion of oil and gas properties. The increase in the 2013 provision compared to 2012 was due to the increase in production, offset by a slight decrease in the overall DD&A rates year-over-year. Per unit depletion rates on just oil and gas properties for the fourth quarter and year ended 2013 were $16.33 and $16.44 per Boe, respectively. That compares to $15.18 and $16.92 for the fourth quarter and year-end 2012. Depletion in the fourth quarter of 2013 increased over the fourth quarter of 2012 because of relatively higher depletion rate in Utica during the current quarter. Utica was not a significant factor in the fourth quarter of 2012 depletion. G&A increased in 2013 compared to 2012, mostly because of an increase in stock-based compensation, payroll and employee benefits. The top half of this next slide reflects results attributable to shareholders for the quarter and year end per GAAP, which includes unrealized gains and losses from mark-to-market hedge positions. All of the events I mentioned in my opening comments are included here, as well as discontinued operations from Colorado dry gas properties that were divested in 2013. The bottom half of the page shows adjusted net income and earnings per share with unrealized hedge gains and losses removed, but includes $123 million cumulative after-tax impact of the Piceance impairment and the charge for early extinguishment of debt in the fourth quarter of 2012, both nonrecurring events. We've left these costs in the table to be consistent with our prior presentations. For the year ended 2013, the net loss includes $28.9 million impairment, as I mentioned earlier. Adjusting for these nonrecurring costs, we would have reported a net income of approximately $3 million for the year ended 2012 and a net income of approximately $29 million for the year ended 2013. In 2013, we extended the maturity of PDC's revolver to 2018 and have maintained a borrowing base of $450 million. Our credit agreement calls for redeterminations in May and November 2014, and we'll be evaluating the need to increase the borrowing base, probably late in 2014. We exited 2013 with $193 million of cash, which, along with an undrawn revolver, cash flow from 2014 operations, is expected to fund our capital program for the year. We are projecting to begin borrowing on the revolver in the second half of this year. The timing will depend on the expected timing of additional rigs in the Wattenberg and Utica. The table on this page reflects PDC's consolidated borrowings. Our consolidated financial statements include our proportionate share of our Marcellus joint venture debt, which has drawn $52 million to PDC's interest at year end. The joint venture debt is nonrecourse to PDC and doesn't count against PDC's $450 million borrowing base. Liquidity, including cash on hand and available borrowing base at December 31, 2013, is approximately $630 million. Our hedge positions for 2014, '15 and '16 are shown on this page. We've hedged substantially all of our oil and gas production that we're allowed to hedge under the terms of our credit agreement for 2014. For 2015, about 50% of our allowable production is hedged based on our new reserve report as of year-end 2013. And we're working on adding to our 2015 and 2016 positions. Our philosophy hasn't changed on hedges. We held off recently on oil hedges for 2016 and beyond, as we believe the curve will come back some over time. Our gas hedges are all in the $4 range, and we are selling at higher prices today. However, we don't think current prices will hold long term, and we expect to take advantage of the current run-up while we can. Our last slide is a look at our 2014 financial guidance. We provided the market with guidance for capital expenditures and production back in December. We expect production this year to be a little less lumpy than last year because of additional drilling rigs added last year. However, we do expect that pad drilling will continue to cause both a lag in turn-in times and stair steps in production when these pads are turned off to sales. We intend to deploy a fifth rig in Wattenberg in the second quarter of 2014, and a second rig in Utica in the fourth quarter of the year. So we don't expect to see any production from these rigs in the first half of the year. Our guidance for 2014 uses the range of prices around NYMEX futures as of the 1st of November, 2013, as shown on this page. Oil differentials are projected to widen a little in 2014 compared to last year. Wattenberg differentials are projected to average about $12 off NYMEX per barrel for 2014. Utica oil differentials are projected to be about $10 per barrel off NYMEX for the year. If you compare the midpoint of 2014 guidance to the results in 2013, we are forecasting an increase of about 32% in adjusted EBITDA and about 37% increase in adjusted cash flow for 2014. With that, I'll turn this over to Bart for some discussion on operations.

[Barton R. Brookman:]

Thank you, Gysle, and hello, everyone. Let me start by thanking our operating and EHS teams for all their efforts in 2013. In spite of excessively high line pressures, particularly in the first half of the year, a 1,000-year flood event and very early severe weather conditions across all our operations, we hit our production targets and slightly exceeded our midpoint of our guidance. Again, great job to our district employees. As Gysle noted, production for 2013 was 7.4 million barrels, up slightly from the previously announced 7.3 million barrels due to some additional non-operated volumes in the fourth quarter. This is a 35% annualized increase from 2012 levels. The company's proved reserves grew 38% to 266 million barrels, and we had a record 1,300% reserve replacement. The Wattenberg production for the company in 2013 grew 33% from 2012 levels. Our Marcellus production grew 23%, and the company established its first full year of Utica production. Let me give some production highlights. Again, we're very pleased we exceeded the midpoint of our production guidance. In 2013, we experienced tremendous production growth, something we expect to continue in 2014 and 2015. Our Waste Management pad downspacing project. The production from this is currently exceeding our expectations. The Codell performance on this project is in line with our 370,000 barrels of oil equivalent-type curve. And the Niobrara performance from this project is in line with 400,000 barrels of oil equivalent, middle area, Niobrara-type curve. We deployed the fourth rig late in 2013 in the Wattenberg Field, which is just beginning to contribute to production. We're extremely pleased overall with the Utica results, 11 wells currently in line. For the company, we had strong liquid production growth in 2013, approaching 11,000 barrels of oil equivalent per day or a 53% liquid mix. The pie chart in the upper left corner of the slide shows the breakout of our liquid mix, total -- coming in at 53% total liquid mix. We promised a strong production jump in the fourth quarter and we delivered on this, as reflected in the lower right bar graph. This bar graph also shows our 2013 quarterly production guidance and our strong production performance, as we met or exceeded expectations in 2013 quarter-by-quarter. And so far in the first quarter of this year, we are very pleased with our overall production levels. Here's a quick overview of the reserves we announced several weeks ago. Year-end 2013 reserves came in at 266 million barrels and a 54% liquid mix and an SEC PV value of $2.7 billion. A quick walk through, year-end 2012 through year-end 2013 proved reserves. Year-end 2012, we had 193 million barrels of proved reserves. We divested 16 million, primarily the Rockies gas properties, produced 7.4 million, and improved our operations drilling and pricing for a total of 95.4 million barrel improvement, primarily in the Wattenberg Field, and had acquisitions of 1.1 million barrels to end 2013 at 266 million barrels. Again, a 38% improvement. And jump over to the Wattenberg, give a quick update on Niobrara program. We continue to be very pleased with the overall performance of this drilling program. This is an update of our 3 type curves for the core Wattenberg. We now have 650 wells in our database to generate these 3 area type curves. The outer core type curve has been increased to 285,000 barrels of oil equivalent, the middle core type curve has been increased to 400,000 barrels of oil equivalent, and the inner core type curve remains at 500,000 barrels of oil equivalent. Economics are noted for each area. You can see the excellent drilling returns and PV10s we generate per drilling project. All of the economics you see have been updated for the additional data we have gathered and we are running these economics at $90 oil flat, $4 natural gas flat, and we have increased our oil deduct long term to $10 a barrel. In 2014, expect our drilling programs to be a good blend of the outer, middle and inner core drilling projects. Next, an update on the horizontal Codell program in the core Wattenberg Field. Our type curve here has been increased to 370,000 barrels of oil equivalent. 37 wells were included in our type curve development. You can see the excellent returns, over 70% for this Codell program. On a per-well basis, we're generating a PV10 of approximately $4.7 million per well. Again, approximately 50% of our 2014 Wattenberg drilling program will be targeting the Codell formation. Let me give an update on the Utica project. Currently we're drilling our 14th well in Eastern Ohio, on a 3-well Palmer pad in the southern portion of our acreage position. 11 wells were drilled and online year-end 2013 at a rate of 5,200 barrels of oil equivalent per day. Currently, we're experiencing fairly stabilized production as we continue to hold back pressure on the wells within the condensate window. Overall, we're extremely pleased with the production levels from this project. Expect very strong production growth over the next several months as 2 additional Garvin wells and a 3-well Palmer pad are scheduled to come online. A little more detail on the Garvin wells. We announced the 1H several months ago. We have 2 offsets to this, the 2H and the 3H. The completions, or fracs, are done on both these laterals. One is a 4,800-foot lateral, the second is a 6,800-foot lateral and we executed 58 stages combined for the 2 laterals. We anticipate first sales on both these wells over the next 30 days as we will rest 1 well 15 days and the second well for 30 days. Right now, overall drilling in the Utica, we are on target for our 18 wells we budgeted for 2014, and we will be adding the second drilling rig sometime this fall. A quick update for overall drilling activity for the company in 2013. The company operated or spud 95 horizontal wells. 70 of those were in the Wattenberg Field

[Operator:]

[Operator Instructions] Our first question comes from Ryan Oatman with SunTrust.

[Ryan Oatman:]

Yes, I'll ask kind of the obvious question here. I mean, 4Q production very strong relative to plan. Sounds like some non-operated production came in. How much of that was known in early December when you provided guidance? And do you anticipate taking a look at that ahead of this Analyst Day coming up here?

[Barton R. Brookman:]

Is the question specifically referring to the non-operated production, Ryan?

[Ryan Oatman:]

No, just overall production of the 9.5 million to 10 million barrels. Just curious if there's a potential upside to that, kind of based on what you saw in 4Q, maybe being a little bit above plan?

[Barton R. Brookman:]

There's several parts to this. First of all, yes, we were very pleased with fourth quarter. We had a lot of completions that did towards the end of the quarter. We had the O'Connor plant come online. We saw some flush production. So there was a lot of forces, particularly in December, we had very strong production. But remember, we did lay down the Marcellus drilling rig, which was incorporated into our budgeting. So in 2014, with the exception of the Armstrong-Reynolds pad, we really have a decline in our Marcellus production. That gap has to be filled by Wattenberg and Utica. We expect great growth in both the Wattenberg and Utica as we go through 2014. It's going to be higher margin production. And so bottom line is, we're going to map all of this out on a quarter-by-quarter basis when we get to Analyst Day but there's a lot of moving parts to your question. And we need to take -- it's hard to do without showing some graphs and different pieces and parts of where we're going.

[Ryan Oatman:]

Right, absolutely. I'll defer until April then. Kind of shifting over to the Utica now. It does seem like there has been increased activity, especially in the dry gas window. You guys mentioned a little bit in terms of your activity towards increasing that leasehold. Do you have any additional color at this time or do you want to just defer until April? And I'll leave it at that.

[James M. Trimble:]

Really, I think what we can just say is, we're looking to add acreage. We don't have anything right now.

[Operator:]

Our next question comes from Irene Haas with Wunderlich Securities.

[Irene O. Haas:]

Back to Southern Utica, in Washington County. Can I have a little more color on the 10 wells you're going to be drilling in the southern acreage? And what I'm kind of after is generally location. Is it closer to Morgan County or whatnot? Can you shed some light on it?

[Barton R. Brookman:]

Yes, I can. Right now, we've got the 3 Palmer wells. We'll be moving up to Guernsey County for a 4-well pad and then another 4-well pad in Guernsey. And then we will be moving, Irene, kind of halfway between. And we'll give flavor, all of this, in April. But we'll be moving halfway between Guernsey in the southern acreage, trending back down south. So we've got what we call the Miley pad that we're going to drill. That is actually changing a little bit due to some land swaps and things that we've had. So we've got a little bit of a tweak update to our overall drilling but nothing dramatic. So bottom line is, we've kind of got 8 in the very north, 5 in the very south and a batch of wells kind of in the middle. We're kind of splitting the difference.

[Operator:]

Our next question comes from Kyle Rhodes with RBC.

[Kyle Rhodes:]

I was just wondering if you can provide some updated production histories for the Garvin and Neill wells on your Washington County acreage?

[Barton R. Brookman:]

There's not a whole lot. The Neill is holding in about what we announced. We have artificial lift that have installed here in the last month that's really up and running reliable here the last couple of weeks. We continue to get frac fluid back on that. And we've told the market that, as far as landing the lateral, we were a little bit disappointed in particularly the first half of the lateral, where we were substantially low from our target zones. So we're getting a lot more frac fluid back on that well but it continues to clean up. And then the Garvin well is just back online here over the last week. We did shut it in while we executed the 2 completions I outlined, on the 2H and the 3H. And so it's back online. And as we told the market, that well is exhibiting fairly stable production. We continue to manage it on a smaller choke. And I would just go back to the production rates that we had announced. And we'll give full updates on type curves and production for all areas in the Utica in April.

[Kyle Rhodes:]

Okay, that's fair. And I guess switching over to the Marcellus, just wondering how that asset fits in the PDCE portfolio longer term?

[James M. Trimble:]

All right. It's a great dry gas asset that we've got and it's in the JV. It's all HBP, so it's not anything we have to be drilling. We've been delineating over the last couple of years the various acreage blocks we've got there. And so we'll just continue to monitor. We've been looking at some options to maybe bring in some outside money into it but no decision's been made to do anything different than what we've been doing with that asset. It's old legacy acreage, so it fits basically in the program and it's there for when gas prices recover.

[Kyle Rhodes:]

Okay. And then just one final one for me. Just wondering what duration of resting period you guys are budgeting for your Utica wells in 2014, just in terms of your 2014 production guidance?

[Barton R. Brookman:]

We budgeted, I believe -- I believe we budgeted the 60 day. It's either 30 or 60. That's something we can clarify in April.

[Kyle Rhodes:]

Okay. So fair to say there might be some upside if you've kind of got these 2, the 2 Garvin wells, one's a 15, one's a 30-day. If you kind of shift to a shorter duration, there's some upside to that guidance?

[Barton R. Brookman:]

Yes, there would be some upside, absolutely.

[Operator:]

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

[David R. Tameron:]

Can you guys talk about differentials? Just what you're seeing out there and -- there's been a lot of talk about that. Can you just address that?

[Lance A. Lauck:]

Yes, sure, David. It's Lance. So as Gysle talked about earlier, we're projecting a differential of crude oil at Wattenberg around $12 per barrel for 2014. And that comes from a series of markets that we have put in place for the current year. I think though longer term, Dave, we see the differential coming down closer to around $10 a barrel. And some of the key drivers of that are, first off, that all the different takeaway capacities are coming out of the basin. As you know, the Plains rail facility is up and running. That happened in the fourth quarter. That's around 68,000 barrels a day. And then we have the White Cliffs expansion that's happening sometime later this year of about 70,000 barrels a day. And then Tallgrass is going to bring a spur into Wattenberg. That's going to be about 90,000 barrels a day. And that's projected, I believe, around the first quarter of 2015. So with all those incremental takeaway capacities in place, we feel good that the long-term differential for Wattenberg is going to be closer to around $10 a barrel.

[David R. Tameron:]

Okay. And what are you guys seeing right now in the field? Are you seeing -- it just seems like recently there's been a lot of talk that it's been running better than the differentials with pipe recently. Is that fair?

[Lance A. Lauck:]

We've seen, for one of the months here in the first quarter, saw a little bit of tightening inside of that $12. But I think in general, when we look at it, there's a lot of different supply and demand factors that are going on with that. And I think what we're just comfortable at this point saying, Dave, the full year is around $12 a barrel as our number.

[David R. Tameron:]

Okay. And then I think, Bart, you alluded to it, just kind of the ramp in the Wattenberg is going to be a little less -- or I guess the company production profile is going to be a little less lumpy than in prior years. How do you -- how should we think about the DJ ramp overall? I mean, are you -- has it been kind of consistent quarter-to-quarter? How is that -- how should that play out?

[Barton R. Brookman:]

As we go -- right now in the Wattenberg, we've got quarter-to-quarter production growth modeled. And to the point of adding the additional rigs, the fourth and the fifth rig, in particular, we added the fourth rig at the end of last year and the fifth is coming in May. So David, you'll see an acceleration of the growth rate as we go through the second half of '14. I do know we have growth every quarter going through the year. So -- and we'll cover a lot of this in April, trying to model out how this thing -- one big change for the Wattenberg, and we're going to try to paint this picture, but we've talked about spuds in the past, but as we get to the bigger and bigger pads, probably more critical is turn on line. So we're going to try to make a shift to not continue to talk about spud counts, but also start talking about turn on lines because it's really key when you use term kind of lumpiness. We're going to have some big blocks, some big stair -- call them, stair-step increases in the Wattenberg. Particularly, a great example is the Waste Management pad. It started coming on in October, November, December timeframe, and it really helped drive growth in the fourth quarter for the company. Hopefully I answered your question.

[Operator:]

The next question comes from Curtis Trimble with Global Hunter.

[Curtis Ryan Trimble:]

Just to follow-up on Dave's comment, let's see if we can get a little granularity, maybe a quarterly progression of production growth towards that 9 million to 10 million barrel figure for the full year 2014?

[Barton R. Brookman:]

We're going to provide all of that at Analyst Day. But I can tell you this, we do have nice growth modeled as we go through the year.

[Curtis Ryan Trimble:]

Okay, very good. Maybe another idea about the breakdown of production from Utica vis–à–vis from the Wattenberg?

[Barton R. Brookman:]

We have not provided any of that. And again, we'll have to defer until April for that.

[Operator:]

Our next question comes from Chris Stevens with KeyBanc.

[Jack N. Aydin:]

This is Jack. Two questions, could you give us -- in terms of the production in the fourth quarter, you have non-op. Could you tell us how much of that fourth quarter production in Wattenberg was non-op?

[Barton R. Brookman:]

I can. Well, let me cut it into 2 pieces here for you, Jack. For annualized, and these are estimates, annualized 2013, we had 500,000 barrels equivalent of non-op production. At the end of the year approximately December or exiting the year, approximately 2,500 barrels equivalent per day of non-op production. So I think that comes out to 7% or 8% of our total production for the company.

[Jack N. Aydin:]

When do you get the data from the non-op people? Do you get them on timely or are you estimating them on a quarterly? How do you account for it in a way on your quarterly basis?

[Barton R. Brookman:]

We get the data hopefully timely. That's been one of the challenges. The systems are getting better as far as our linking to the other operators. And yes, we do make some estimates in there and then we adjust those estimates based on actuals. Sometimes the actual settlement can be several months after the actual month of production. So Jack, there is a time lag there. Gysle's group and our operating teams are working diligently. I think everybody is aware this is a growing part of our business, capital-wise and activity-wise and production-wise. So we've got improving systems to address the growth in this area. So we're confident we won't have future adjustments. But we are relying -- I always need to put the warning out, we are relying on other operators to timely provide this data to us.

[Jack N. Aydin:]

Okay. A second question for me, you sound very excited about the Waste Management. You mentioned a couple of times. Could you put some numbers around it? What is -- at the year end, what that production was from Waste Management and what is running at today?

[Barton R. Brookman:]

Oh boy, Jack. I don't have those numbers of the top of my head. I can tell you this

[Operator:]

Our next question comes from Jeffrey Connolly with Mizuho Securities.

[Jeffrey Connolly:]

Can you just remind us what downspacing test you guys have planned for the Wattenberg later this year?

[Barton R. Brookman:]

Yes. Really, 3 projects to talk about. First 2 I'll touch on are operated and they are more in the middle, inner cores. So the inner 2 sections of the core Wattenberg. 2 projects. One is a 22 well -- let me step back, both of them are 22 well equivalent per section projects, Codell and Niobrara. It will be a combination of Codell, Niobrara B and Niobrara C. So that's a step up from the 16 for the Waste Management package. And again, those are both operated. Both of those, I believe, are planned to be spud sometime this summer. Then we have a non-operated project in the northeastern part of the field, Section 9 of 663, up near Wells Ranch. Noble is the operator. It is 26 wells across 1 section, just in the Niobrara. So we'll have 13 wells in the Niobrara B and 13 wells in the Niobrara C. We were updated this week on that project. That is going to spud, hopefully, sometime May-June timeframe. And we anticipate it will be coming online somewhere around the end of the year.

[Jeffrey Connolly:]

And then what factors drove CapEx below plan in 2013?

[Barton R. Brookman:]

Well, the biggie was we executed less refracs in the Wattenberg. Miscellaneous capital in Wattenberg, some office expenses and different things came in under. As I noted, Utica was slightly above. Some of that was land and some of that was the capital structure per well ended up -- some of that was science and technology that we overspent a little bit. And then corporately, we spent a few million dollars less on just general capital items corporately. Overall, we were very, very pleased. I mean, our capital budget came in really close in all 3 divisions to what we anticipated.

[Operator:]

Our next question comes from Adam Michael with Miller Tabak.

[Adam R. Michael:]

I wanted to revisit, I guess, some of the guidance you gave back in December on the longer laterals and maybe some of the expectations you guys have. I saw that there was 19 horizontals budgeted this year. They're over 7,000 feet. And I was wondering what kind of internal rates of return or PV10s you guys are expecting and what these wells would cost compared to the type curves and the data you have in your current presentations?

[Barton R. Brookman:]

Okay, and let me take a stab at this. Obviously, we're executing these to enhance the economics, lower our drilling F&D. Let me start with the -- and these are -- again, there's about 19, 20 of these in the budget. That number is actually moving a little bit based on the acreage configuration and the final geological plan. But we think about 10% or 15% of our drilling program is going to be these longer laterals. Completion-wise, we'll be more like 25 to 30 stages. They're going to be around 7,000-foot. The cost structure is going to be somewhere between $5.8 million in the low $6 million, depending on the final lateral length, the number of stages. The rates of return, we anticipate in most of these -- most of these are going to be in the middle and inner core areas. And the rates of return -- I guess the answer I would give, I would look at our type curve currently, take those, and yes, we expect the economics to get enhanced above those rates of returns and obviously above those PV10s on a per well basis. I don't have the actual projected rate of returns in front of me. But we're going to give a lot more clarity on these approximately 20 projects in April. And we're getting a lot of data right now, publicly, on our peers who have attempted longer laterals. So we're really, really moving up the knowledge base for these types of projects.

[Adam R. Michael:]

Okay, that's helpful. I do know that Noble's had some very encouraging results but that's helpful. And then I guess my second question, when I look back at 2013, and I look at the Wattenberg inner, middle and outer core, where were most of the wells focused in '13? And I think the comment was that they're going to be spread more evenly this year.

[Barton R. Brookman:]

And Adam, the bulk of our drilling program, really '12 and '13, has been more focused on the outer portion of that middle and that outer area. And for really 1 specific reason, we were waiting on processing facilities to come online. So we were trying to drill in the lower GOR areas, trying to minimize the amount of natural gas gathering we needed. And also, economics, chasing some of the oily areas. The economics, obviously, from those type curves are enhanced as we go more towards the inner and the middle. We've got a lot of flexibility now on the processing side since the O'Connor plant is up and running and the Lucerne plant is scheduled for the first half of '15. And so that gives us much more flexibility to drill throughout the field. So you'll see a migration as we go through this year's drilling program, more into the center part of that middle area and into the inner core area.

[Operator:]

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

[James M. Trimble:]

Thank you, Kevin. And I'd just like to say to everyone, thank you very much for your call ins and your questions today, and we'll be seeing you around. Thanks.

[Operator:]

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