May 1, 2013
Executives
James M. Trimble - Chief Executive Officer, President and Director 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
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Brian M.
Corales - Howard Weil Incorporated, Research Division Trevor Seelye - Wells Fargo Securities, LLC, Research Division Irene O. Haas - Wunderlich Securities Inc., Research Division Adam R.
Michael - Miller Tabak + Co., LLC, Research Division Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division Raymond J.
Deacon - Brean Capital LLC, Research Division David E. Beard - Iberia Capital Partners, Research Division Mark Lear - Crédit Suisse AG, Research Division John Malone - Global Hunter Securities, LLC, Research Division Steve Emerson Mostafa Dahhane - Wunderlich Securities Inc., Research Division
Operator
Greetings, and welcome to the PDC Energy 2013 First 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, the 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, please begin.
James M. Trimble
Thank you, Kevin, and good morning and thank you for joining us today to discuss PDC's First Quarter 2013 results. We posted a slide on our website for today's call.
And let me begin by drawing your attention to our Safe Harbor language as it relates to our forward-looking statements and projections in today's presentation. I will discuss the highlights for the quarter followed by additional detail from Gysle on financials, and then Bart on operations.
We are very pleased with our results from the first quarter of 2013 production from continuous operation increased to 18,500 barrels of oil equivalent per day representing a 19% increase over first quarter 2012 and a 10% increase over fourth quarter of 2012. Growth was driven primarily by Wattenberg, which included the continued success of our horizontal drilling program and our 2012 asset acquisition.
We also grew Marcellus production year-over-year. We're executing on our stated strategy to grow our liquids production, percent liquids, and cash margin.
We set an all-time company record on liquid production for the quarter at just over 10,000 barrels per day. Company-wide, our liquid mix from continuous operation was approximately 54%, this was driven by 16% year-over-year increase in liquids from the Wattenberg Field, coupled with our planned divestiture of non-core dry gas in Colorado.
To give you an idea of the impact on production mix on the increased liquid volumes, coupled with the pending non-core sale, our mix in previous quarter was 36% liquids in the fourth quarter of 2012, and just 33% in the third quarter of last year. The financial impact of the higher liquid mix is at our cash margin, which is sales less G&A and production cost, from continuous operations are approximately $29 per BOE in the first quarter.
That is nearly double the full year average in 2012 of $16 per BOE from all of our assets. We realized a net loss for the first quarter of $39 million or $1.30 per diluted share primarily as a result of an impairment related to our shallow upper Devonian dry gas wells in Appalachia.
As we've done over the last 2 years, we continued to evaluate our asset base, exploring the opportunities to divest additional dry gas assets such as our shallow upper Devonian gas wells in Appalachia, which led us to impair these properties. The net loss was also the result of unrealized losses on our commodity hedges.
Backing out the impairment and unrealized commodity losses, we will have a net income of $9 million or $0.25 per share. Gysle will expand on this shortly.
Net cash flow from operations increased 5% to $52 million for the first quarter of 2013, compared to $50 million for the first quarter of 2012. Bart will update you to -- on operations shortly, but I want to emphasize that we're very pleased with our continued success in both the horizontal Niobrara and Codell drillings program in the Wattenberg Field.
We expect to start our waste management pad this month, with the arrival of our third horizontal drilling rig in the Wattenberg Field. This project targets 16 horizontal wells per section, targeting both the Niobrara B and C as well as the Codell formation, and represents our tightest operational horizontal down spacing test to date.
In the Utica Shale play in southeast Ohio, we are finishing the third horizontal well of the Starters' 3-well pad in Guernsey County. We will then move the rig to our southern acreage and begin drilling operations in Washington County.
There, the rig will drill 2 horizontal wells, the Garvin and the Neill, each on separate pads. We did have some minimal production in the first quarter from the Utica as we tested the Guernsey County wells.
We added a small refrigeration unit toward the end of March, which is allowing us to test the natural gas liquids volumes, and to boost into a temporary gas sales line. We are on target to permanently connect our Guernsey County wells to the MarkWest systems in late June.
At present, we have a total of 4 rigs running, all drilling horizontal wells, 2 in the Niobrara play, 1 in the Utica and 1 in Marcellus. And as I said, we expect the third rig in the Niobrara will arrive shortly.
We continue to focus on maintaining a strong balance sheet and expect to be able to fund our 2013 development budget with the cash flow and the proceeds from the Colorado asset sales. We are currently in our semi-annual redetermination process with our bank group.
We requested an extension of the maturity date of the revolving credit facility to 2018, along with the confirmation of our current $450 million borrowing base post closing of the non-core assets. As of the end of March, we have $388 million of available liquidity on a consolidated basis.
We anticipate closing of the sale of our non-core Colorado assets in the second quarter. We made significant process toward closing and have only a few remaining items in order to finalize the deal.
So in summary, PDC had a very good start to the year with solid results from our Wattenberg operations. We continue to focus on adding value to our shareholders, and are in an excellent position with our solid hedged portfolio and ample liquidity to continue to execute our 2013 capital program and business plan.
I would now turn the call over to Gysle for his financial review of the first quarter of 2013.
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 please see our press release and our 10-Q filed this morning.
As a reminder, we announced earlier this quarter, earlier this year that we'll begin reporting our results in barrels of oil equivalent. You may have heard Jim refer to that in his discussion.
So from this quarter on, you'll be hearing BOEs instead of gas equivalents as in the past. Let's look at summary results.
Total sales on Slide 6 are from continuing operations and exclude realized hedging gains and losses for the quarter. Results from continuing operations also exclude sales from Piceance, our northeast Colorado field and 3 non-core Wattenberg wells, included in our recently announced sale that is expected to close in the second quarter this year.
As Jim mentioned, PDC had a record quarter for liquids production and that's the driver for the 19% increase in revenue for the current quarter over the first quarter last year. Liquids production, including oil NGLs, made up 54% of production on a BOE basis in the current quarter.
Gas production from continuing operations also increased about 17% over the first quarter of 2012. Wellhead prices for oil were lower in the current quarter, averaging $86.96 compared to $92.86 in the first quarter last year.
Lower oil prices were offset by higher prices for gas at the wellhead in the current quarter. Our average realized gas price was $3.09 in the current quarter compared to $2.58 in the first quarter last year.
NGL pricing improved to $30.48 per barrel, from $28 per barrel in the first quarter last year. Overall for the quarter, weighted average wellhead price was $47.71 per BOE, a 1% increase in the first quarter 2012.
Production cost from continuing operations for the current quarter were $15.9 million or $9.52 per BOE compared to $12.9 million or $9.12 per BOE in the first quarter 2012. Production costs included lifting cost, production taxes and field overhead.
The $0.40 per BOE increase in production cost is attributable to the slight increase in production taxes per BOE and an increase in field overhead per unit cost. Lifting cost per BOE actually decreased in the current quarter compared to the first quarter last year and Bart will add more color in a few minutes.
Gross margins from continuing operations were the driver of our improved cash margins, as Jim mentioned. Gross margins are sales less production cost before realized gains or losses from hedging in each period.
Increased production resulted in $63.5 million of gross margin from continuing operations in the quarter, $9.4 million improvement over the first quarter of 2012. Margin from continuing operations in the current quarter is about 80% of sales.
That compares to about 72% gross margin in the fourth quarter last year before the announced sale of Colorado gas properties. Adjusted cash flow and adjusted EBITDA include results from discontinued operations and our non-GAAP measures that we include -- that we reconciled with GAAP in our 10-Q and press release.
They include net realized hedge gains of $8.5 million before taxes in the first quarter this year compared to $9.9 million in the first quarter of 2012. Unrealized hedged gains and losses are excluded from both adjusted EBITDA and adjusted cash flow.
Adjusted EBITDA in the current quarter excludes the pretax impairment of $45 million that Jim mentioned earlier. Adjusted EBITDA for the first quarter of 2012 includes pretax gain on sale of Permian properties of $20.3 million.
Stripping out the impact from the sale of properties in the first quarter last year and comparing adjusted EBITDA only from oil and gas operations, the current quarter increased about $6 million over the first quarter last year. Adjusted cash flow from operations increased $2.7 million compared to the first quarter last year as a result of the increased production in the current quarter.
Adjusted EBITDA per diluted share also reflects the gain on sale of the Permian properties in the first quarter last year. Excluding that gain on sale, adjusted EBITDA per diluted share in the first quarter 2012 would have been $2.31 per diluted share based on 23.9 million shares compared to $2.02 per diluted share on 30.3 million shares in the current quarter.
DD&A and G&A from continuing operations were pretty steady in the quarter compared to the current quarter last year. On a BOE-produced basis, both of these costs are decreasing as we continue to ramp up production.
Next slide, the top half of the page reflects results attributable to shareholders for the current -- for the quarter for GAAP, which includes unrealized gains and losses from mark-to-market hedge positions as well as discontinued operations. We recorded after-tax net realized hedge losses of about $19 million in the first quarter 2013 compared to after-tax net unrealized gain in the first quarter 2012 of about $1 million.
The bottom half of the page shows adjusted net incomes and earnings per share with unrealized hedges -- hedging gains and losses removed. There is a reconciliation of these numbers in the appendix of this presentation and in this morning's press release.
Adjusted net income and loss numbers include both net gain on the sale of the Permian properties in 2012 and the impairment in the current quarter. We have consistently used this format but it does require further analysis.
The current quarter includes the impairment I mentioned of about $28 million after-tax. The first quarter 2012 includes the after-tax gain of about $12.6 million related in the sale of the Permian assets.
Adjusted net income from all operations, normalized for these 2 nonrecurring events, would be about $8 million or $0.25 per share, as Jim mentioned, for the first quarter 2013; and about $2 million or $0.10 per share for the first quarter 2012. Keep in mind that we had additional 6.5 million shares outstanding in the first quarter 2013 from the June 2012 equity offering compared to the first quarter last year.
Debt maturity schedule -- Jim's stole my thunder here with his comments about the credit facility amendment. We are expecting better pricing overall on the amended facility, as Jim mentioned, and are asking the banks to maintain our borrowing base at $450 million.
This amendment is expected to be completed on or before May 10. At the end of the quarter, we had $376 million of liquidity under the existing facility.
With the closing of the sale of our Colorado non-core assets, we will retire the balance on this facility and add cash available for our capital program during the year. We expect to begin drawing on the credit facility again in the fourth quarter.
This last slide looks at our hedge positions as of March 31, 2013, excluding hedges that will be transferred upon the closing of the Colorado non-core gas assets. Our natural gas hedges -- oil and natural gas hedges are fully hedged under the terms of our credit facility for the remainder of 2013, being 80% of total crude production.
We are very close to fully hedged on the same basis for 2014. 2015 is still a work in progress and we expect we will complete it by year end or sooner.
You can see from this schedule that gas is swapped at an average price of just over $4 per MMBtu for all periods presented. Oil is a combination of swaps and collars in the range of $90 per barrel.
As you all know, we aggressively hedge our production to protect our cash flow and capital program. There is more detail on our individual hedges in the 10-Q we're filing this morning.
With that, I'll turn this over to Bart for comments on operations for the quarter.
Barton R. Brookman
Thank you, Gysle, and hello, everyone. A very strong quarter for the company's operations.
Very pleased all of our basins performed at or above our expectations. Production was 1.7 million barrels for the quarter, or 18,500 barrels of oil equivalent per day average.
83% of the company's production was from the Wattenberg Field. We're very pleased, as Jim noted, the first quarter we're able to report production from our Utica project.
Overall for the quarter, we had a 19% increase in our production from continued operations compared to first quarter of 2012 and, as Jim called out, a 10% jump from the fourth quarter of last year. Let me cover some highlights of production.
Overall, production was 4% above our expectations or guidance. It's important to note that oil beat our expectations by 9%, the majority of that coming from the Wattenberg Field.
Natural gas beat our expectations by 2%, and natural gas liquids were just under our expectations at 3% below guidance levels. The NGL shortfall was primarily due to the assumptions we have in our models related to ethane rejection.
In the Utica, as previously announced, we tested the Onega Commissioners well and the Detweiler well with very strong initial rates, and we're happy to establish first production on our Detweiler well in mid-March through a temporary midstream solution. As represented in the bar graph, expect production for the company to accelerate as we progress through the year.
This acceleration is due to an additional rig in the Wattenberg Field, which should begin drilling sometime mid-May, and the startup of several midstream expansions in the Wattenberg Field, which are on schedule. Production by area.
Wattenberg, again, our biggest producer at 1.4 million barrels, you can see first production from the company in the Utica, modest levels of production. I should note that this is very intermittent production in nature, given we were flow testing both the Detweiler and the Onega wells.
In the Marcellus, 263,000 barrels of oil equivalent, so obviously 100% gas play. That equates to 1.6 Bcf equivalent, and that is PDC's net within the Mountaineer JV.
And the total from continued ops for the company was 1.7 million barrels. The commodity mix for the company per the pie chart, 40% oil, 14% NGLs, for a total the liquid mix of 54% and 46% natural gas.
The commodity mix is represented in the lower bar graph for each basin, Wattenberg and Utica both being our liquid-rich areas and the Appalachia being our dry gas basin. Quick update on the drilling activity.
For the quarter, the company spud 17 horizontal wells. In the Wattenberg Field, 4 horizontal Niobraras and 7 horizontal Codells for a total of 11 in that field.
2 wells were spud in the Utica, and 4 wells were spud in the Marcellus and Harrison County, West Virginia. We conducted 6 re-fracs or re-completes in the Wattenberg Field and participated in at an average working interest of approximately 20%, 10 non-operated projects in the Wattenberg Field.
From the bar graph, you can see relative to plan, we're slightly ahead in our drilling activity. But overall, we are on pace both at operated and non-operated for the 131 wells to be drilled in 2013.
Current rig activity for the company. Two horizontal rigs in the Wattenberg Field.
And again, we anticipate a third rig will be running there in approximately 2 weeks. We have 1 horizontal rig running in the Utica on our Stiers pad.
We're currently drilling on the third well and we should reach TD on that project today. We have 1 horizontal rig in the Marcellus, and we are currently on the third well out of 4 wells on the D'Annunzio pad in the Harrison County.
Quick update on the capital budget. For the first quarter, the company spent $50 million within PDC, and $4 million within the Mountaineer JV.
The $50 million is slightly under our estimates for the first quarter primarily due to 3 reasons: lower working interest on the 10 non-operated projects in Wattenberg Field than we assumed in our budget; slightly fewer re-fracs and re-completes in the Wattenberg Field; and the timing of a few completions that rolled into the second quarter within the Wattenberg Field. Overall, when you look at the full year 2013 estimate of $386 million for our annual budget, we anticipate being very close to that number.
So expect the acceleration of our capital in the remaining 3 quarters of the year. Lease operating expenses, we're very pleased with where our costs are going.
Lifting cost for the quarter came in at $4.48 per barrel of oil equivalent, $0.40 under our operating plan or guidance, and $0.63 improvement from our 2012 levels. Drivers -- some high-level drivers of the improvements in lifting cost.
First, our work-over expenses have been lower than expected. Expect modest increase in these in the remaining 3 quarters of the year.
Obviously, with the increased production that helps the overall ratios, but very important and a call out to our operating teams and our EHS group, very strong management of our environmental costs both in Wattenberg and the Marcellus related to ongoing increased regulations in Colorado and West Virginia. Again, per the bar graph, we're very pleased with overall where the costs came in.
So some operational highlights in Wattenberg. Quarterly production from the horizontal program is very, very strong.
And approximately 6,000 barrels of oil equivalent per day or 40% of that base is production. We drilled the 11 wells in the quarter 4 Niobraras; 7 Codells.
Our Codell wells continue to perform at levels above our horizontal Niobrara program. Our drilling complete cost per well remained at $4.2 million.
We now have 6 down space pads completed and online and are currently producing and gaining data from the A, B and C benches of the Niobrara with very positive results. Our well performance consistently continues to fall within our reserve range of 300,000 to 500,000 of barrels of oil equivalent per well.
Our third party midstream expansions in the Wattenberg Field are on schedule for start-up this fall. And lastly, we do plan to spud our waste management 16 well per section down space test in mid-May and should have results in production from that project sometime in the fall.
In the Utica. Our acreage position now stands at 46,000 acres.
Most of our acreage is in the liquid-rich window. Our first and second horizontal wells tested 1,800 barrels of oil equivalent and 2,200 barrels of oil equivalent per day respectively.
We're currently on our 3-well pad in Guernsey County and, again, a third well on that pad reached TD today. Next week we'll move to Washington County and spud our first delineation well of our southern acreage.
Multiple midstream options are either finalized or being finalized in the Utica play. First, we did sign with MarkWest in our northern Guernsey County acreage last month; and second, we are finalizing an agreement for midstream in our southern acreage which we anticipate should be in place approximately 30 days from now.
And then the Marcellus. We initiated drilling in Harrison County West Virginia on a 4-well pad in late January.
We should have production beginning on that pad in July. Expect very strong production growth from our Marcellus operations as we go through the second half of the year.
And overall, for the quarter, we are very pleased with our operating team both in the Devonian and the Marcellus on the overall production levels. With that, I'm going to turn this back over to the operator for Q&A.
Operator
[Operator Instructions] Our first question comes from Welles Fitzpatrick with Johnson Rice.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
On the southern Utica takeaway options, is it reasonable that we expect those terms to be relatively similar to the ones outlined in the north at Analyst Day?
Lance A. Lauck
Yes, Welles, this is Lance. Based upon the work that we've been pushing through with regard to the southern Utica, we do anticipate the terms to be reasonably the same with that of what we executed in the northern area of Guernsey County.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
Okay. And then on the 2 existing Utica wells, anything to shift your thinking on the EURs that you outlined at Analyst Day?
And obviously, you haven't completed the Stiers wells yet, but anything to shift your thinking on -- I think it's $8.5 million was the last completed well cost you guys had put out there.
Barton R. Brookman
Nothing to shift our thinking on either. Again, what we're flowing into right now on the Detweiler is our own JT plant on location and a temporary, somewhat limited, pipeline, temporary pipeline solution.
We really need to get both those wells into our MarkWest pipeline system and their processing to really fully understand that the full deliverability of the wells, so nothing as far as our type curve performance. And on the cost side, our AFEs continue to come in about $9 million a well.
We still have a goal with the team long-term in the development mode to try to drive that closer to $7.5 million, but right now, I think $8.5 million to $9 million is a good number.
Operator
Our next question comes from Ryan Oatman with SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Most of my questions on the Utica were just answered. But on the operating expense, it looks that came in below plan.
Is there a chance for that to tick downward based on existing plan, or do you expect it to kind of tick back up towards guidance once you do a little bit more of these re-fracs, et cetera?
Barton R. Brookman
Oh boy, I think the best answer there is that we would expect that to fall between first quarter levels and guidance that we provided. I don't know if I have enough knowledge right now, Ryan, for the balance of the year to say we're going to be off guidance.
Gysle, I don't know if you have anything you want to add to that.
Gysle R. Shellum
No, I think you're on target there.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay, fair enough. And then in the south, surprised to see the midstream agreement moving forward at this point.
It sounds like you guys are certainly confident of what you have down there. Are there any provisions that will require certain deliverability, et cetera, from the south that you feel like there's flexibility in that midstream agreement towards that southern Utica acreage?
James M. Trimble
Ryan, no. We're working with a pipeline to be able to test our wells and get that done, but there is no deliverability volumes that we need to contractually be involved with.
Operator
Our next question comes from Brian Corales with Howard Weil.
Brian M. Corales - Howard Weil Incorporated, Research Division
Another operator talking to Wattenberg of potentially going as tight as 20 acre spacing, I mean, what are your thoughts there?
Barton R. Brookman
Oh boy, that came, I think that happened yesterday. And I believe it was 16 wells in the B-bench and 16 wells in the C-bench, if I remember right, for a very aggressive.
I think the answer would be, I go back to our Analyst Day presentation. Scott Reasoner presented our technical data that supports a 40-acre down-spacing.
The real key to that methodology is you're going in to 2 different benches at the Niobrara, so that ends up being more like 20 acre spacing in the Niobrara. Let me answer it this way, I hope they're right, but we're not there yet.
And as we talked to Jim about this yesterday, we want to test these ourselves or get public data, and then come to the market and talk about additional inventory gains. We feel very good about where we're at with our 2,000 locations right now in our 3P, which is 16 wells total, 12 in the Niobrara, 4 in the Codell.
Brian M. Corales - Howard Weil Incorporated, Research Division
Okay. And as you I guess, get more information over the next year or so, what -- is this $4.2 million, in terms of well cost, could you see that come down as, I guess, you're drilling more on pads?
And what do you think that can get to?
Barton R. Brookman
The answer is $4.2 million, I would stick with that number. We have operating efficiencies right now that are helping those costs, but we also have some demand-pull in this basin going on with this mini-boom in the Wattenberg.
So we've got 2 forces happening right now. I think the net-net is -- the $4.2 million is a good number to stick with.
Brian M. Corales - Howard Weil Incorporated, Research Division
Okay. If I could just do one more as well.
Is there -- are you all looking for more acreage either in the Utica or the Niobrara, whether it's a southern area of Utica or kind of the greater Wattenberg Field? And if so, is there much available?
James M. Trimble
Well, let me -- I guess really, we have -- in the budget, we've got about $7 million or $10 million budget in Utica to pick up both on acreage around our existing acreage. We're not looking to try to pick up big acreage blocks in the Utica.
And so in Wattenberg, we are constantly looking at opportunities there. But there, everything in the Wattenberg Field is leased up.
And it's just a question of if people find something that you can acquire. We're always looking, but we don't have anything budgeted.
Operator
[Operator Instructions] Our next question comes from Trevor Seelye with Wells Fargo.
Trevor Seelye - Wells Fargo Securities, LLC, Research Division
Just a couple of quick questions. Can you maybe explain the temporary midstream solution in the Utica a little bit?
And is that something that you might be able to use in the south when you guys drill those first couple of wells?
Barton R. Brookman
The first part, the explanation, it is some of the old low-pressure shallow gathering in the area that is volume-limited and really not designed for Utica-type production. We struck a deal on a short-term basis to test our well that entailed us having a set of JT plant at the surface.
So we currently have our -- at least our oil going to the tanks, our gas going through a JT plant. We actually -- I think George actually presented a photo of this.
We have a bullet on location. We're selling our NGLs to MarkWest, and then the residue gas to one of the small local gatherers.
So that's physically what's going on without giving any of the terms of the deal. The second part of your question is, no.
This company is not going to provide additional testing in our southern acreage. But just to add a little more flavor to Lance's earlier answer, the southern midstream solution, we don't anticipate significant waiting on pipeline delays because the proximity of their lines and their facility startups are going to be closer aligned with our frac schedule, if that makes sense.
So we're hoping we can go through our tier period in the southern acreage and quickly go to sales.
Trevor Seelye - Wells Fargo Securities, LLC, Research Division
And then I guess on Marcellus, with sort of the recent improvement in gas prices, what are the thoughts, the partnership thoughts of going any faster there, maybe in the back half of this year, even probably more into 2014?
Barton R. Brookman
Well, we haven't even really had discussions. What we want our team to do there is get back up and drilling, get to drilling -- we have a new company on the drilling force right now.
Get our production to start ramping in the second half of the year. And Trevor, I would say that would be part of our budgeting process in October and November that we work with Jim and our Board of Directors.
And obviously, the big wildcard is where are gas prices going to be second half of this year, and where will gas prices be next year and then 2015. Would we consider that the economics are there?
Sure. But it'd be early for us to try to predict where that's going.
Jim, I don't know if you want to...
Trevor Seelye - Wells Fargo Securities, LLC, Research Division
And then the last one I had is, on the Codell in your Analyst Day presentation, you guys showed that blue line surrounding your acreage. Can you talk about what that line is?
I mean I know it caused some debate with some other operators that are outside the line, so maybe is it just thickness or some other characteristic that caused that line?
Gysle R. Shellum
So Trevor, the outline of the Codell was the picture that we have as far as the Codell itself. And so we provided an outline of the core area.
Not saying that the Codell outside of that is not productive, but it's thins out as you get outside that line that we depicted on that slide. And so as we look at it, that's why we focused on the acreage that we have inside there which has been a consistent thickness of Codell that has been exploited throughout several years vertically and is now being drilled horizontally.
Barton R. Brookman
I think the slide you were referring to Trevor, we were really trying to define the Codell potential, that slide was strictly dedicated to Codell.
Operator
Our next question comes from Irene Haas with Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
I have a question on Washington County and Utica play. Your Garvin and Neill well, I'm wondering how long it would take to drill and will there be a resting period?
And so when should we expect results? And then after that, how many follow-up wells would do have for this general area?
Has it been glued down or somewhat contingent on the first 2 wells? Then lastly, how's the terrain?
If you decide to really get aggressive, how quickly can you build a drill site?
Barton R. Brookman
Okay. So first part of the question is the Garvin and Neill, we'll spud the Garvin hopefully next Thursday.
We'll most likely cure those, Irene, for 30 to 45 days. And as I noted, we're hoping we'll be quick to sales on those projects.
Based on the success, yes, after the Garvin and Neill, we will move north back up to Guernsey County, where we will drill another 4 wells while we evaluate the Garvin and Neill. And we will have locations ready to spud very late in the year 2 more additional wells in our southern acreage based on the results of the Garvin and Neill.
So we're trying to be as logical as we can about all this, given we'd like to have some IPs in maybe 30 days or 60 days of production to support additional drilling. There's some other operators right now.
We're hoping they'll have some announcements, will help our confidence levels in the southern acreage. And then the last part of your question, related to drill locations.
Our team's doing a really good job here. Ohio, the counties are working with us -- the locations right now, we're out ahead of this.
We don't anticipate there'd be any delays in our capital program here related to us building locations.
Irene O. Haas - Wunderlich Securities Inc., Research Division
Okay, great, how many days will it take you to drill the Neill well and the Garvin well?
Barton R. Brookman
Those are -- approximately 20 to 30 days drill time.
Operator
Our next question comes from Adam Michael of Miller Tabak.
Adam R. Michael - Miller Tabak + Co., LLC, Research Division
I wanted to ask a couple of questions on the wells management -- the waste management pad, if that's 16 wells, I think at the Analyst Day you guys mentioned spud-to-spud time is 12 to 15 days. I'm just trying to figure out, like from a timing perspective, when that puts us 6 to 7 months out if it's just one rig drilling on that pad.
Will all those wells be brought on at the same time? Or how do you plan to kind of -- how should we model that, I guess, going forward?
Barton R. Brookman
Yes. And Adam, it's a good question.
And the team's actually working on a couple of different options. Here's how we have it modeled.
We have a model coming on early October of this year. We will have 2 rigs actually dedicated to this project at one point, not a perfect split on all 16 wells, but we'll have 2 rigs actually dedicated to drilling this project out.
We also are considering some SIMOPS, and SIMOPS are where we'll be frac-ing one pad and drilling on another pad. That has not been finalized yet.
That would pull forward in the year, maybe a September-type timeframe, some of the early rates on these projects, but we have not finalized these SIMOPS. So right now, the answer to your question is expect the October 1 type of production.
And most likely, we will be bringing all 16 wells over a couple week period on together. We're actually drilling these 16 wells from 4 different pads.
Adam R. Michael - Miller Tabak + Co., LLC, Research Division
Okay, that helps. And then my second question was the second and third rigs that will be running, I mean, it sounds like 1 will also be focused on the waste management pad.
But should we just assume that the rigs are going to be drilling on 4 well pads going forward? So it's a little bit more like a stair step on production coming on?
Barton R. Brookman
I think almost everything we have are 4 to 5 to 6 well pads in our drilling program. And the other rigs balance of this year will really dedicated to that northern-- northeastern
Gysle R. Shellum
The Wells Ranch area.
Barton R. Brookman
The Wells Ranch area in the northern part of our acreage.
Operator
Our next question comes from Jack Aydin with KeyBanc.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
Question, are you guys thinking about adding a fourth rig to the Wattenberg to accelerate the development of the asset base?
James M. Trimble
Jack, at Analyst Day, we talked about that we don't have plans in the budget to bring a fourth rig in this year, but in the long-range plan, we said that in 2014, we're looking at bringing in a fourth rig at that time. And kind of just saying, when the overlap occurs, whether it's, either the end of this year or the first quarter next year, that hasn't been identified yet.
But our intent is, yes, to bring in a fourth rig.
Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division
My next question is to Gysle. How did you -- could you run for us how did you arrive at the $8 million net income from operation?
Could you run the numbers for us please?
Gysle R. Shellum
I'll do -- just to give you a quick overview. We used an effective tax rate on the impairment and on the gain on sale of about 38%, a little bit north of that.
So that's going to be the difference in numbers that I've been some of you guys write about. And the number that we presented is a little bit higher, effective tax rate for the quarter.
If you use that and use the $45 million impairment and the gain on sale for 2012 and use that number as well for the unrealized gains and losses, you should be at close to $8 million.
Operator
Our next question comes from Ray Deacon with Brean Capital.
Raymond J. Deacon - Brean Capital LLC, Research Division
My question was about the Utica. I was wondering whether there has been any other competitor results that you know of in your southern acreage in Washington that would make you more encouraged in, kind of, where well cost are I think just [indiscernible] mentioned they turn [ph] to the drilling wells for $5.9 million this morning, which is lower than I thought was possible.
But anyway, that it.
Barton R. Brookman
Yes. And Ray, since we saw each other 3 weeks ago, I'm not sure we have anything significant.
We've heard rumor in the center of Noble County that there is a very strong well. Again, that's a stream [ph] rumor.
We heard there's a substantial flare out there. It's similar to where the Miley wells were reported.
On the cost side, I don't think -- and again, so much is driven by the completions here. And if anything, our $9 million estimate is being driven by the fact that we're trying to get probably more stages per thousand foot of lateral right now, seems to be the trend in this play.
So I can't comment on where that number comes from and I haven't seen the AFE. I can tell you I have talked to some of our peers in Guernsey County and in Noble County, I think their AFEs are in 8 to 9.
Jim, we talked about this. So that seems to be a fairly consistent now.
For 5,000, 6,000 foot laterals with maybe somewhere around 20 or 25 stages.
Raymond J. Deacon - Brean Capital LLC, Research Division
Okay, got it. And I was just curious, if you can elaborate a little bit more on the slide that you talked about on the Codell at the Analyst Meeting, do you have a way of knowing whether your peer results to the south of you are kind of looking like your Codell results so far?
And any kind of updated thoughts on how the wells are hanging in there relative to the B-bench wells?
James M. Trimble
Ray, I think right now, from what we presented at Analyst Day, we haven't gotten any additional data from our offset operators down there. We're still holding sort of where we were at that time.
Monitoring but we just haven't seen any new data since then.
Operator
Our next question comes from David Beard with Iberia.
David E. Beard - Iberia Capital Partners, Research Division
Just wondered if you could elaborate a little more on the production numbers you released up in the Utica and maybe what we can and cannot take away from that, because I know there's a lot of moving parts. But if you'd beat at 17,000 barrels, and it sounds like it was 2 weeks of just the Detweiler, is there a way we can look at production rates or has the well just been tilt back, and days divided by flows is too difficult to use?
Barton R. Brookman
Yes, I would not -- I would take it for a milestone for the company that we had our first sales in this project, but it is almost impossible to take the quarterly volumes and conclude anything as far as daily rates or...
James M. Trimble
Yes, I'd tell you, one of the things we -- as I said, this is both from both wells up there from testing. It's also -- we're swapping a lot of data and trading information right now.
And so we've been reluctant to put out stuff that we're, actually has value for us to swap until we get more information. So look for us, once we get it permanently hooked up, to be able to report more specific information.
Operator
Our next question comes from Mark Lear with Crédit Suisse.
Mark Lear - Crédit Suisse AG, Research Division
Just getting back to the spacing in Wattenberg, a lot of good data from your Analyst Day on the pads and talking about 16 well locations per section, beyond that, what will give you the confidence ultimately to have that sort of data translate into your location count?
Barton R. Brookman
I think the answer is data, production data. I think we've got a lot of things, technically Microseismic, and Scott presented some of this in his Microseismic modeling.
Our peers are doing some more aggressive testing, but in the end, I think the way we'll present this to the market is as we gain knowledge with production data, working with our reserve group and our reserve auditors, we'll continue to expand that 2000 location inventory.
John Malone - Global Hunter Securities, LLC, Research Division
I mean ultimately, where do you think that could go just based on that 16 wells per 640?
James M. Trimble
Mark, I think what we saying at this time, we're -- we put out a 3P number being the 2000 locations. We're going to be doing some testing as Bart said.
And I really don't want to be speculating how many -- I mean you can do the calculation and come up with a range as well. But we really don't want to be speculating until we get more data.
We've been adding, every year, we'll keep adding to it based on data and I guess what we'll be doing at the end of this year, will be adding based on what we get this year.
Barton R. Brookman
I hope I can answer that question in the fourth quarter.
Mark Lear - Crédit Suisse AG, Research Division
Yes, yes. No, I understand.
I mean it just seems like a lot of that -- a lot of great data coming out of the Analyst Day with the pads and it felt like-- not seeing the location count change much. It seemed like that would've been some of the data you could kind of rely on but, if it's more data than, I guess, we can be patient.
Operator
Our next question comes from Steve Emerson with Emerson Investment Group.
Steve Emerson
Gentlemen, in terms of your pad for the 16 location, 40-acre test, are you going to -- in view of industry data that may be coming out, are you going to try to put a few 20-acre downspacing wells in to test the limits of the possibilities here? Or basically you're pretty well set in your current plan for 16 well per section-type test?
Barton R. Brookman
Steve, we've submitted this permit. it's approved by the state of Colorado.
So this is project we've had in planning for 6 months. So there won't be any significant changes to the overall design of this pad.
By the end of the year to your question and the total 69, there will be some things that we do different patterns. But on this pad, no.
Steve Emerson
Okay. So if I hear you right, you may have some further downspacing tests or wells at some other locations this year?
Barton R. Brookman
That's correct.
Operator
Our next question comes from Mo Dahhane from Wunderlich Securities.
Mostafa Dahhane - Wunderlich Securities Inc., Research Division
Just had a quick question on the production from the Wattenberg. Looks like you guys participated in 10 horizontal wells, about 3 more than you guys expected.
Was that a driver for the strong production, or actually it was just due to good wells?
Barton R. Brookman
No, this is spud count, so most likely, a lot of that production didn't have huge impacts in the first quarter. So really, that's really just an activity analysis not a production analysis.
Operator
And our next question is a follow-up question from Welles Fitzpatrick with Johnson Rice.
Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division
I think I heard you guys say that it was 12 -- on the waste management, you said it was 12 Niobraras and 4 Codells. Did I mishear that or have you guys shifted from the 10 Niobrara, 6 Codell plan that was in the Analyst Day packet?
James M. Trimble
So the waste management pad itself, Welles, is a total of 10 Niobrara wells, 6 in the B, 4 in the C bench and then 6 Codell wells, the total there being 16 for that section.
Unknown Analyst
Okay. Then I'm sorry I misheard you, I apologize.
And what's the tightest offset on the laterals that you guys are testing in between the B and the C on that pad?
James M. Trimble
It's 40 acres.
Barton R. Brookman
Well, I don't have the schematic in front of me, but I believe Jim's right, it's 40 acres.
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
Thank you, Kevin. And I'd like to say thank you, everyone for your participation and calling in today.
We look forward to next quarter. Thank you.
Operator
Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.