Ranger Oil Corp (ROCC) 2012 Q4 法說會逐字稿

Good day, everyone, and welcome to the Penn Virginia Corporation fourth-quarter 2012 earnings conference call. Today's call is being recorded. At this time, I would like to turn the conference over to Mr. Baird Whitehead. Please go ahead, sir.

Thank you, April.

Good morning, and welcome to Penn Virginia's fourth quarter 2012 conference call. I am joined today by various members of our team including Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our CFO; John Brooks, our Executive VP of Operations; and Jim Dean, our Vice President of Corporate Development.

Prior to getting started, we would like to remind you that the language in our forward-looking statements sections of the press release, as issued last night, as well as the Form 10-K, which will be filed early next week, will apply to our comments this morning. We would like to begin our discussion by expanding on the earnings release that was issued after the close yesterday. The fourth quarter of 2012 continued a trend of solid financial results, achieving our sixth consecutive quarter of EBITDAX of $60 million or greater with year-over-year increases in oil and natural gas liquid revenues and gross operating margins. We continue to drill excellent Eagle Ford wells in both Gonzales and Lavaca Counties. And at this time we have almost completely de-risked our entire Lavaca County acreage position. Our fourth quarter benefited from the addition of the third drilling rig late in the third quarter. And we enter 2013 with operational momentum. Our short-term goal was earning all the non-consent acreage in Lavaca County, which involves drilling five more initial unit wells, which we should have done by the April/May time-frame. And in general, getting all of our acreage shale by production in both Lavaca and Gonzales Counties, which we would expect to have completed by the end of this year.

Before we discuss the details of the quarter, I wanted to touch on a number of recent developments which are significant for Penn Virginia. As we discussed in the past, we have taken steps towards the second half of 2012 through asset sales and equity offerings to improve our balance sheet and liquidity. It had an un-drawn credit facility and approximately $18 million of cash on hand at the end of 2012 for over $3 million of total liquidity. As a result, we expect to be able to fully fund our 2013 capital expenditures through cash, cash flows from operations, and our revolver borrowings. In addition, we are also considering the sale of a 40% interest over much of our acreage position in Lavaca County, where at this time we expect to have 94% working interest since our partner has not consented the majority of the initial unit wells in that county. This transaction would reduce any operational, any subsequent capital risk, and improve liquidity further. But I want to point out that completing this transaction is not necessarily to fund our 2013 CapEx program. And the guidance which we will disclose and discuss today is not predicated upon a sale that's working interest. At the end of the day, if we don't get what we consider an acceptable price, we will retain higher working interest in Lavaca County going forward.

We have continued to increase our acreage position in the Eagle Ford, and now we have about 33,000 net acres and approximately 300 remaining drilling locations, [or we feel] an approximate 8-year inventory assuming a three-rig ongoing drilling program. Sequentially, as compared to the third quarter on a pro forma basis to exclude Appalachia, production was up slightly and above the upper-end of our guidance range. Fourth-quarter production was 15,444 barrels equivalent per day, compared to 15,245 barrels of oil equivalent per day in the third quarter, excluding the effect of the Appalachian properties. As announced yesterday, our production for January was approximately 15,600 barrels of oil equivalent per day. At this time we are just now beginning to see the benefit of that third rig in Eagle Ford.

Oil and natural gas liquid production increased to 56% of our total volumes, compared to 52% in the third quarter, and is expected to be over 60% of 2013 production. Oil production alone is expected to increase between 23% and 37% during 2013, as compared to 2012. Total peak revenues in the fourth quarter increased slightly and were $53.48 per barrels of oil equivalent prior to the hedges, compared to $50.25 per barrel oil equivalent in the third quarter. Oil and natural gas liquids were 83% of fourth-quarter product revenues, compared to 84% in the third quarter, and are expected to be over 85% of our product revenues during 2013. Suggested EBITDAX was $62.3 million in the fourth quarter versus $61.2 million in the third quarter, primarily due to slightly higher product revenues in spite of the sale of Appalachia and lower operating expenses. During 2012, adjusted EBITDAX was $247.6 million, and is expected to range between $235 million and $280 million during 2013. Our gross operating margin per barrel oil equivalent remains strong, increasing 15% from $34.11 per barrel oil equivalent in the third quarter to $39.29 per barrel oil equivalent in the fourth quarter due to our ongoing shift to oil and NGLs, as well as lower operating costs.

The Eagle Ford Shale is a focus of our growth over the past two years, and will continue to be such during 2013 as we plan to spend approximately 88% of our total CapEx in this play. Steve will discuss the CapEx in a little bit in much more detail. Our Eagle Ford Shale results remain excellent. Along with the premium oil pricing we are receiving since we sell into the LLS market, as well as ongoing emphasis on lowering capital and operating costs, we believe we have a very strategic acreage position within this leading domestic oil shale play. And we are well-positioned in continuing to grow our oil and liquids production. As detailed in our operational update, we reported year-end reserves of 113.5 million barrels of oil equivalent, 40% of which were oil and NGLs, and 41% of which were crude developed.

Eagle Ford crude reserves increased 161% from approximately 10 million barrels of oil equivalent to 26.1 million barrels equivalent for approximately 23% of the total Company crude reserves. The PV-10 of the crude reserves in Eagle Ford alone were about $600 million. If you look at the three plays in Eagle Ford at year-end, we are about 70 million barrels of oil equivalent and over $1 billion worth of PV-10. We therefore think we have significant room to continue to grow our crude reserves in value of the Eagle Ford alone. We also believe we can continue to add to our Eagle Ford drilling inventory due to the fact we have demonstrated we can continue to add acreage to our current position. 69 Eagle Ford wells are currently producing and include 54 wells in Gonzales County and 15 wells in Lavaca County. Three rigs are currently drilling in the play.

Results of the recent wells drilled and completed were detailed in our January 29th operational release, as well as details about our latest notable well, the Techni-18, which were disclosed in the earnings release. That well tested 1,136 barrels of oil a day and about 1.9 million cubic feet a day flowing with about 2,400 [times]. This is a very good well. In fact, it's the best well we have drilled to date in Lavaca County. Post-processing our Eagle Ford production for the quarter was approximately 6,900 barrels of oil equivalent per day, as compared to approximately 6,300 barrels of oil equivalent per day in the third quarter, and averaged 80% of oil, 11% NGLs, and 9% residue gas during the fourth quarter. Due to the addition of the third rig late in the third quarter in 2012, we expect quarterly Eagle Ford production to continue to increase during 2013. In fact, it will make up about half of our total 2013 production.

In Gonzales County, our year-end median PUD EUR is about 400,000 barrels equivalent. In Lavaca County, the same statistic is approximately 500,000 barrels of oil equivalent. The projected EURs for our PUDs are based not only, of course, on nearby PDP performance but also the anticipated lateral length of those PUDs. If you remember as of year-end 2011, our third-party engineer had assigned a little over 300,000 barrels of oil equivalent for our PUDs in Gonzales County. So the well's performance in our drilling results to-date reinforced increasing that 300,000 to 400,000 at the end of this past year. It's disclosed in our operational release our seven most recent Lavaca County [Eagle Ford] wells averaged 21 frac stages, a wellhead IP of 905 barrels of oil equivalent, a 30-day wellhead IP of 642 for the appropriate five wells. The Technik in Lavaca County with 18 frac stages and a wellhead IP of 1,445 barrels of oil per equivalent per day.

I just want to remind everybody, typically, we hold much higher back pressures in Lavaca County due to the higher reservoir pressures in general that we see in that area. In Gonzales County, our six most recent Eagle Ford wells averaged 19 frac stages, a wellhead IP of 884 barrels of oil equivalent per day, and a 30-day wellhead IP of 609 barrels of oil equivalent per day for the appropriate four wells. We continue to make operational progress in the drilling of these wells. During the fourth quarter of 2012, the average Eagle Ford well had 20 frac stages and cost a little over $10 million. During the first nine months of 2012, the average well had 16 frac stages and cost about $9.7 million. The increased overall costs were not only due to the increased number of frac stages in the fourth quarter but also due to the fact that a greater number of wells were drilled on Lavaca County, which have a higher drilling cost than those in Gonzales County due to this [intermediate string] of pipe that we have to set. We also had a few operational issues on a couple of Lavaca County wells which were mentioned in the press release. And I will get into a little bit more detail in that in a second.

What really demonstrates our effort to reduce costs is on the completion side. The all-in average cost per frac stage in the fourth quarter was $289,000, whereas that same cost in the first three quarters was $369,000. This all-in cost not only includes the pumping, and chemicals, and [propping] costs that you typically think of as far as the frac job itself. But it also includes cool tubing, perforating any wire line and plugs, flow-back costs, fuel, and labor. This is a reduction of about 22% as 2012 progressed. So clearly, we are making progress on the cost side that I feel will begin to become much clearer as 2013 program progresses.

We continue to use only high-strength white sand as profit in Gonzales County and a mixture of high-strength white and ceramic in Lavaca County. We continue to self-source our proppant, guar, and acid. In fact, self-sourcing the guar ourselves has saved us $400,000 to $500,000 per well. We continue to take steps to reduce our costs, which I think will be primarily driven on the completion side in 2013. One thing, also important to mention, you'll start to see us undertake more pad drilling as this year goes on. Since much of our acreage is now held by production, it makes a lot more sense for us to come in and start down-spacing, which will further drive some efficiencies and reduce costs further.

The operational problems that I mentioned previously include a few casing stream problems in Lavaca County, which we think is due to the higher frac pressures we experienced. Which most times you're pumping pretty close to 11,000 [times]. We have had some coupling issues. This has added to our fourth-quarter costs. We recently upgraded to a new coupling. We think we have this problem behind us. And therefore, those additional costs we saw late last year should no longer be a problem in 2013.

We expect to stick with the three-rig program and drill 38 Eagle Ford wells. About 29 net this year, with 22 gross, 15.2 net in Gonzales County; and 16 gross, 13.6 net in Lavaca County. With the three rigs, we can expect to continue to drill the 35 to 40 gross wells per year. The stated goal of ours at a minimum is to maintain our multiple-year drilling inventory by acquiring 4,000 to 5,000 bolt-on acres annually at a total cost of $10 million to $20 million. Over the past two years, we have clearly demonstrated that this can be accomplished. This 4,000 to 5,000 acres per year will replace the 35 to 40 wells that we would drill annually with this three-rig program. In fact, in 2012, we picked up approximately 7,900 net acres in Eagle Ford alone. We feel over the next few years that maintaining this ongoing inventory of 300 locations with three drilling rigs is very achievable. But having said that, we will continue to review [oily] acquisition opportunities, primarily in Eagle Ford. And in addition, implement ideas of our new venture team that allows us to test our internally-generated ideas and grow organically. In fact, one of those early ideas is the Pearsall Shale. Just to bring you up to date, we recently TDed our initial horizontal test into Pearsall in Gonzales County. We have just initiated completion work. We expect we should have the results of that well sometime by the end of this first quarter.

So with that, I'd like to turn it over to Steve Hartman, so he can provide an update of our financial progress for the quarter.

Thank you, Baird. And good morning, everyone.

First off, a quick note that you will notice now that we're reporting in BOE rather than in Mcfe, since our production and revenue have been greater than 50% derived from oil and NGLs for the last few quarters, we feel it is more appropriate to report in barrels. So that's how we will be reporting it in our 10-K and our earnings release going forward.

Product revenues were $76 million or $53.48 per BOE, which has slightly exceeded our guidance provided in the third quarter. Revenues were up only slightly over last quarter. But on a per barrel basis they were up 6% as we continue to increase our higher margin Eagle Ford production. You may recall, cash proceeds from hedging are not included in our reported revenue number. In the fourth quarter, we realized $5.5 million cash proceeds. This equates to a $7.03 per barrel increase in our realized oil price, and a $0.42 per Mcf increase in our realized natural gas price. Including the effects of hedges, our realized oil price was $106.33 per barrel, and our realized gas price was $3.83 per Mcf.

You can see we are benefiting from selling our Eagle Ford oil on the LLS market, as Baird explained, with our net back price this quarter at $9 above WTI. 83% of our product revenues were derived from oil and NGL sales. Operating expenses were down 17% this quarter at $20 million. This equates to $14.19 per BOE compared to $16.14 per BOE in the third quarter, a 12% decrease in the per unit cost. Lease operating expense was a little higher this quarter, primarily due to electing to complete some discretionary work-overs in East Texas that were expensed and from some higher environmental and water disposal costs. These were offset, to some extent, by achieving lower overall gas LOE costs, due to selling our properties in West Virginia, Virginia, and Kentucky in the third quarter. The fourth quarter was the first full quarter where we saw the benefit of lower gas LOE due to the sale.

Gathering, processing, and transportation expenses were lower, primarily due to the divestiture of the properties I just mentioned, offset by slightly higher costs in Granite Wash. Production and ad valorem taxes were 41% lower at $2.7 million. This, again, is primarily due to the sale of the property and tax rebates received in the fourth quarter. Our taxes were 3.6% of product revenues, compared to 6.1% in the third quarter. Cash G&A expense decreased 20% to $8.3 million this quarter. This was primarily due to having a $1.4 million restructuring cost in the third quarter related to closing our Pittsburgh office, which we obviously didn't have in the fourth quarter. And we did have a $1.7 million non-cash charge to G&A in our share-based compensation category. And that is due to investing of some executive long-term comp related to reaching retirement age. And this was not in our 2012 guidance.

Our gross operating margin and non- GAAP measure that's generally defined as product revenues, less direct cash operating expenses, increased 15% or $5 per BOE over last quarter from $34.11 to $39.29 per BOE in the fourth quarter. These statistics do not include the additional favorable impacts of our hedges. This increase in our gross margin is a result of investment and continued growth in the Eagle Ford. Our gross operating margin in Eagle Ford production was approximately $80 per BOE in 2012. And that does not include any allocated G&A or hedges. But you can see, as we continue to ramp up our volume in Eagle Ford and decline off the lower-margin natural gas that company-wide gross operating margin is continuing to increase.

Adjusted EBITDAX and non-GAAP measure, which is generally EBITDAX with the cash proceeds of hedges included, was $62.3 million for the quarter, which is 2% higher than last quarter. As Baird mentioned, this is our sixth consecutive quarter with adjusted EBITDAX over $60 million. Our loss attributable to common shareholders for the quarter, which includes the effect of deducting $1.7 million of preferred stock dividends, was $56.1 million or $1.05 per diluted share. This was impacted by a $75 million pre-tax impairment of our Marcellus assets, which is a result of the write-down due to lower gas prices in our Marcellus properties. Adjusted net loss, which excludes certain nonrecurring items such as the impairment and is reconciled in the press release, was $0.22 per diluted share.

Capital expenditures for the quarter were $118 million, up from $85 million in the third quarter. For 2012, we ended the year at $385 million of CapEx, which is $34 million higher than the top-end of guidance we provided in October and $41 million higher than the midpoint. The primary driver of the increase, as Baird explained, is the pick-up in working interest in Lavaca County acreage, which was about $14 million for the quarter. We also accelerated the completion of three wells in December, which had been scheduled to be completed in January. That was about $7 million. We added approximately 1,000 net acres to Gonzales and Lavaca County beyond what was anticipated. So that was good news, and adds about $3 million. And we also had some longer well lateral's than originally planned, some operational issues, as Baird explained. And all of those together, in addition with the Pearsall test, was about $17 million.

Moving on to capital resources and liquidity. At year-end, we had nothing outstanding on our $300 million credit facility at $18 million of cash on the balance sheet. Currently, we have $28 million drawn on the credit facility, $4 million in cash, and $2 million in letters of credit outstanding for $274 million of liquidity. Our 2012 adjusted EBITDAX was $248 million, and our total debt to adjusted EBITDAX ratio or leverage was 2.3 times compared to our permitted covenant in the credit facility of 4.5 times. So we have plenty of room within that for borrowing capacity. Our next borrowing dates re-determination is coming up in April. We have not yet provided any data to the banks regarding the re-determination, so it is too early to tell what our borrowing base will be this spring. But from what we know so far, we expect it to be no less than what we currently have.

And moving on to hedges, we added some natural gas hedges and oil hedges since the third-quarter call. Our current position by quarter is detailed in the earnings release. We currently have hedge 4,600 barrels per day of oil production for 2013, which is about 58% of the midpoint of guidance. The weighted average [for] price of our portfolio was $97.35 per barrel, which is a blend of our collars and our swaps. We have 20 million a day hedged of natural gas for '13, which is 55% of the midpoint of our guidance. And the weighted average [for] price of that portfolio is $3.76 per MMBtu.

And now on to our 2013 guidance, which is detailed on page 10 of the release. Our current guidance does not include any effects of the JV process in Lavaca County. We will release updated guidance as the JV interest is sold. And as Baird mentioned, our ability to fund the 2013 capital program is not dependent on this sale. Our guidance for capital expenditures is relatively flat to 2012 actual with spending at $362 million to $400 million. Drilling and completion is approximately 85% of expenditures, and about 90% is spent in the Eagle Ford. Lease acquisition includes lease dollars to replace our current drilling inventory at an average cost of $2,500 to $3,000 per acre. We have approximately $15 million allocated to new ventures development, and about $6 million to finish our initial testing of the Pearsall.

Capital is about $50 million to $60 million higher than our preliminary guidance given in October, primarily due to our higher working interests in Lavaca County. Basically, we're going from a 57% working interest to a 94% working interest on our non-consent wells. We are planning for some longer lateral's and pipeline extensions on the Lavaca County acreage. And that is offset by lower exploration dollars and lower spending in the Granite Wash. If we sell the 40% working interest we have in market currently, we expect our capital requirement related to the lower working interest will decrease about $50 million to $60 million. And that does not include any sale proceeds or assumed carry. Our adjusted EBITDAX if we sell this asset will decrease about $25 million to $35 million. And of course, we cannot give any assurances of a deal closing or of the ultimate proceeds of the deal structure. We will update guidance if and when we get a deal signed.

Production guidance is 5.7 million to 6.2 million barrels equivalent or 15,500 to 16,900 BOE per day. Year-over-year, the midpoint is roughly 3% higher than 2012 actual pro forma for the 2012 property sale. We expect oil production to grow at 23% to 37% over 2012 volumes with 30% growth at the midpoint. We expect oil and NGLs together to comprise 60% to 65% of our total production in 2013, compared to 48% in '12 and 56% in the fourth quarter. Production growth was impacted since our preliminary guidance in October, primarily due to lower drilling in Granite Wash and by accelerating from 50% working interest Eagle Ford wells earlier in the 2013 drilling schedule. Product revenues are expected to be $330 million to $364 million in '13. Revenues derived from oil and NGLs are expected to be approximately 87% of total product revenues. Assuming a $90 oil price and a $3.50 gas price for 2013, we would expect to receive about $13 million in cash proceeds from the hedges we have currently in our portfolio.

For LOE, we are guiding toward a flat cost of $4.80 per barrel at the midpoint, which takes into account lower gas LOE as result of the property sale, offset by higher LOE for Eagle Ford oil. For adjusted EBITDAX, which includes cash receipts from hedging, we assume a $257 million midpoint of the given range. This is based on our price assumption of $90 oil and $3.50 natural gas for '13, as I already explained. Assuming the midpoint of this guidance range, adjusted EBITDAX grows 3% over 2012 pro forma to adjust for the contribution from our sole properties, the growth rate is approximately 7%. Now, this may seem like a smaller growth rate than expected, but I assure you the cash flow from our base operations is growing.

There were some significant drivers of cash flow in 2012 that we are not assuming in this guidance. Specifically, we realize the significant LLS premium, the WTI, which I mentioned earlier, was $9 a barrel for the fourth quarter, net of transportation. We are not assuming this higher premium in our 2013 guidance, although we have been seeing it in the first two months of this year. We're also not forecasting as much hedging proceeds. In 2012, we realized $30 million in cash proceeds from hedging, which is included in adjusted EBITDAX. For 2013, we're assuming $13 million, as I just explained. And we do plan to continue to layer in hedges just like we did in 2012, and our budget prices are higher as the market allows us to. Of course, if we start layering in those hedges above $90, that would adjust our adjusted EBITDAX guidance. But that is currently not in our guidance.

Baird, that concludes the guidance review.

Thanks, Steve. Thanks for all the detail.

In conclusion, we continue to execute on, we feel, a very viable strategy. And we've been able to demonstrate that we can grow oil, NGL production, and of course, our oil reserves. We believe that we've got a very strategic, very valuable Eagle Ford asset that we can grow and have grown. We've got a multiple-yield drilling inventory that some folks have been concerned about. We are not concerned about that. And I'm also convinced, with focus on our costs, you are going to see those costs go down in 2013. I also think that you're going to see improved results with the down-spacing, with zipper fracs, those kind of benefits that you would typically see as you go back in and drill some of the better areas of the field. I feel very confident that we are going to see improved results as the year goes on, also.

With that, April, I would like to open up the lines for any questions, please.

(Operator Instructions)

Neal Dingmann of SunTrust.

Baird, you sort of addressed this. I'm just wondering, again, if you don't get the price you want for some of that Lavaca acreage, will you just continue with the three-rig program throughout this year and then reevaluate at the end of next year? Is that the plan?

Yes. We would, Neal. At the end of the day, because we've been so focused on liquidity, that we were concerned about the [aspend] issue. Having said that, if you keep that interest in associated growth and production and resulting EBITDAX, you essentially pay out incremental CapEx with additional working interest in a fairly short period of time because of the quality of the wells that we're drilling. There are pros and cons of either sticking with it or doing it alone. If we don't get something, it makes a tremendous amount of sense to us, we're going to keep doing it alone.

Okay. And then just lastly, not outside of the Eagle Ford, any lease issues there now that you've obviously diverted most of your CapEx to the Eagle Ford that we should look at on the Granite or the Marcellus?

No. Almost everything we have in the Granite Wash, as far as the development area, is HBP. Really, the focus is on just doing what we do. If we were fortunate enough to have a discovery in the Pearsall, I think you would see us uptick that leasing effort, even though we've got a substantial position where we are already in this liquid part of the window. I think you would see us go out there and step up our leasing activity if that Pearsall was an outstanding well. In any case, for right now, we are just focusing on the Eagle Ford.

Got it. Great. Thank you all.

Brian Corales, Howard Weil.

Just to tackle the Pearsall question, is your plan to complete the well tests and see how it flows and then decide what else you're going to do for 2013? Or do you all plan to drill another well already?

We do not have a second well in the budget right now. The plan would be just to sit back and evaluate what we have, Brian. If it is something that's outstanding, I think you would see us probably jump on and try to get another well drilled this year.

From an acreage standpoint, we probably would want to pause and shore up our acreage position in the play before we do too much. Because even though our acreage position is okay, you always want to make it bigger if you can. And there are reasons that we think we could make it bigger if we are successful. So I think you'll see us take a pause lease, and then probably try to get a second well drilled sometime later on this year.

Okay. In the Eagle Ford you all are developing, what are you all assuming now on the down spacing? We've seen other operators talk about 40- and 50-acre down spacing. Where do you all sit today?

And then your 3P number that you gave, the 70 million barrels and $1 billion of PV-10, did that just assume 80-acre spacing? Or what did that assume?

Both. We had some parts of our leasehold on larger spacing, some parts that we could justify right now on down spacing. John, why don't you take that question, if you don't mind?

Sure. Where we have the most wells drilled would be in our Gonzales County. We've got 54 wells drilled there, so we've got a certain amount of confidence in down spacing that down well below 100 acres. So whether or not we get to 40 is another matter. But I think it is safe to say the 60 to 80 range, that's a very viable infield.

In Shiner, where we've only got 15 wells drilled, all our initial wells are drilled on 700-acre units. Those have substantial room for additional down spacing and probably will ultimately end up in that same range that we would forecast for Cortez, being in that 60- to 80- to 100-acre spacing, just depending on the geology and the unit outlines.

And the 3P number of 70 million barrels, you all used a conservative 100-acre spacing for that?

Go ahead, John.

Well, I'll go ahead and let you answer that if you want to, Baird. But I think that's going to reflect the 3P location count that we have, which is around 300 under the infield spacing that we described. I can't give you one infield spacing that is ubiquitous across all our prospects, because it changes. There is 300 drill-able locations in our 3P inventory, which is what that 70 million barrels is based on.

Okay. So on 30,000 acres, it's roughly about 100?

I would say that's right. Some part of the acres you end up not being able to utilize entirely, just because of how these things look, some of these leases are formed. But I would say a good average, if I had to guess, would probably be 90 to 100 acres, Brian.

Okay. That's helpful. Thanks, guys.

[Ray Deacon], Green Capital.

I was wondering if you could talk about any changes to EURs in the Eagle Ford and any potential for well cost productions from here?

Well, let me talk about the reserves. I will turn over the well cost issue to John. We went from a little over 300,000 to 400,000 in Gonzales County as of year-end 2012. Lavaca County, we always have been at 500, our third-party engineers also at 500. So we are consistent there.

Is there room to improve it? Yes, I think there is. I can't tell you exactly what it may go up to, but it is all dependent upon longer laterals. There are different parts of the Eagle Ford that may make sense to drill. As far as the placement of a lateral in better places than others across our acreage position, we are still trying to get our arms around that would improve results.

There's also the case to be made that it is also important to stay in this resistivity zone, even if you had to slow down your drilling just a little bit. We saw that with this Technik well [bunch] standing at high resistivity zone. We ended up with a much better well, the best well we've drilled to-date in Lavaca County. So I don't want to call this a mature play from where we are, because we are still learning. And we think we can make improvements on the results of these wells. As far as the cost goes, John, why don't you jump in on that, please?

You bet. And Baird brings up a good point about the maturity of the play. We drilled 54 wells in Gonzales and just 15 in Lavaca County. So there has been a learning curve for us. In Gonzales, we have a 3-D survey. In Lavaca County, the 3-D survey is currently being shot. We don't have in-hand yet. We expect to have that in the late second quarter. And that will help in the steering and placement of these wells.

But on the 15 wells that we have drilled, there has been a lot of science wells, pilot holes to gather the sub-surface information. And we've just about got the science wells behind us. I think in the first quarter of this year of 2013, we had two more pilots, including a full core in one of those. So in first quarter of '13, you will see some still of the elevated drilling cost in Shiner as we do our science wells.

Going forward, though, and getting away from the science wells and trying to get it more on a manufacturing-type play, where we're doing pad drilling with closer-spaced wells and zipper fracs and getting the completion efficiencies that we anticipate. We are anticipating seeing probably an 8% to 10% reduction on the pad drilling on overall costs.

Also, we have been wholesale-buying our guar and proppant and acid and trying to drive those completion costs down. On the stimulation side, we've got a stimulation contract that rolls over in July. So I think the market has softened quite a bit, and that contract rollover should help us. And we hope to see an additional 8% to 10% on the completion side probably in the third and fourth quarter. So we will probably see some direct results in the cost reduction starting to show up in the second quarter, but in third and fourth is when we anticipate seeing the real big change.

Got it. Great. Thanks, John. What really explained the increase in the oil guidance as a percentage of the overall Bcfe in '13? Was that Gonzales or Lavaca?

It's been mostly an increase in the Lavaca drilling. It is due to the pick-up in working interest. That is the primary driver of any increase in oil.

Okay. Got it. And just one last quick one. Steve, could you go over what exact projects are the mid-stream dollars going for this year?

It is primarily for building out gathering systems for the natural gas out to the various fields. Since we've been trying to drill to hold these non-consent wells and hold acreage, we've had to spend more dollars for facilities and pipelines than we normally would, because we're building up the base infrastructure for the whole play. And of course, as we go back after everything has been earned and held by production, then we will have less facility costs going forward. So it's an initial investment in the infrastructure for the entire play.

Okay. Got it. Great. Thank you.

(Operator Instructions)

Welles Fitzpatrick of Johnson Rice.

If I remember correctly, you guys have been non-consented in about 17 units as of the last update. What's that number looking like now?

John, do you have that answer?

All of them. I think the total number is 21 or maybe 22. I think there is still one unit that we have yet to be completely formed. But we have sent the election to our partner who has non-consented all those and elected to maintain their over-ride. And they have expressed their satisfaction with the way the project is proceeding.

Okay. Perfect. And so then, that whole 21, 22 adds about -- and I know you guys have talked about, I think it's 4,200 net acres being added previously. But that allowed maybe 4,500, 5,000, something in that neighborhood?

I think that's probably a good estimate.

Okay, perfect. And then on the Pearsall, how many stages are you guys looking at with that design? And what is the AFE looking like?

We've got, I think, 18 to 21 stages on this. We're going to try a couple of different things. This will be the most northeastern extension that we know of where the Pearsall has been tested horizontally. So I don't want to commit to one single completion methodology.

So we are going to try a few different things. Overall, I think we'll have somewhere between 18 and 21 stages when it's all said and done. Some will have shorter stage links than others. Some will have longer. We're going to radioactive trace it and see what performs best.

On the capital side, we did have to sub-commit that AFE primarily because of the -- on the pilot hole and getting kicked off is a very deep well. I would be guessing. I don't have that AFE number in front of me. Someone in Radnor may have it. It is a large number. I think on a going-forward basis, we would anticipate our Pearsall wells to have a capital cost similar to what our Lavaca County Eagle Ford wells look like.

Okay, perfect.

John, it's looking like about $10 million to $12 million for this initial test.

Okay.

Great. Thanks so much, guys.

[Steve Furman] with Canaccord.

Baird, where do you anticipate spending the rest of the CapEx outside of the Eagle Ford and Pearsall? I know from time to time in the mid-continent you've done some exploration testing. What is in the budget for anything like that this year?

Well, we have a handful of gross wells in the mid-con -- Granite Wash. We talked about the mid-stream money. The bulk of the other dollars is actually with our new ventures team. We have allocated, I think, $10 million on the land side for the new ventures team and another few million dollars on seismic and data in general.

To drive that, we have not put any wells in there for exploration this year other than this Pearsall. So if we get to the point that we are ready to drill a new ventures well, then we would consider it. And it'll have to stand on its own two feet by the end of the year. But at this time, we've got just leasehold dollars to go in there and start picking up acreage.

Okay. That was it. Thank you.

Justin Schleifer of RBC Capital Markets.

You talked a little bit about this in your opening remarks. But can you give us some more color on the timing of the drilling program and how the rigs might move between Lavaca and Gonzales County?

John, why don't you answer that question, please?

Sure. We're going to continue to, under our current drilling schedule, drill the remaining wells that we have scheduled for the initial unit wells in the Shiner AMI. That should give us a total of 16 wells in Shiner. Then the remainder of the other 22 wells would be drilled in Gonzales.

We have the option of going back and doing some additional pad drilling in Shiner. But we have also got a JV with another major company in Gonzalez that we need to go [split] some JV wells with them later in the year. I think Baird alluded to that earlier in his call, where there's some 50% wells that we're going to get drilled in Gonzalez County as well. So right now it's 16 wells in Lavaca and 22 wells in Gonzales. But that could change in terms of actual numbers between the two.

Okay. Great. Thanks. That's helpful. That is it for me.

[Warren Daro] with Raymond James.

As far as the geology as you all see involving the Pearsall, what have you all said about the Lavaca County> And do your properties there include potential for Pearsall as well?

Well, it would probably be too gassy in Lavaca County. Also probably prohibitively deep and expensive. But it would be dry gas in Lavaca County. At this time, we are not recognizing any value for the Pearsall in Lavaca County.

Okay. I appreciate it. Are you still seeing the 500,000 EUR in the Lavaca County? Is that an updated guess at this time?

That is correct.

Okay. Thank you.

Phillip Pennell of Mariner Capital.

In terms of the firm transportation commitments, has all of that now been charged off?

We have charged everything off in West Virginia associated with our sale of Appalachia. We still have firm associated with the Marcellus that we still have outstanding. We continue to sell that firm on a month-to-month basis, but we still have some firm there.

But everything that's basically not going to be used on a go-forward basis. I'm assuming the Marcellus is [pooling] enough to where that you can still sell that if you're not using it for existing production?

That is correct. We may not get full market rate, but we can sell it.

Yes. You can sell it so the charges should be relatively de minimus compared to what's been taken.

Yes. We have firm on National Fuel, and we have some firm on Dominion. It kicks in. Later on this year, the firm on National Fuel is fairly insignificant in cost.

Okay. In terms of the rest of the gas reserves, are there any leases there that need to be drilled on for HBP purposes? Or is pretty much everything held now?

Almost everything is held. Our Mississippi stuff, it's almost all held. We have some things in East Texas associated with the Haynesville, specifically, that selectively we may let expire. We may elect to renew just because we do have a very good area in the Haynesville. It does not make sense to drill today, but at some point in time we think it will. We may want to try to preserve some acreage that is not HBP in the Haynesville. But most of that is HBP.

Okay. Fair enough. Final question. Obviously, the big guy down in Eagle Ford, he comes out and says, we've got drilling these Gonzales wells that are IPing at 6,000-plus. Are we going to see anything like that?

I am never going to say never. Where the big guy is you are referring to, they have a very thick -- there's geological reasons why they have those very good wells. It is very thick. Eagle Ford, probably, 400-feet to 500-feet thick. Where we are is typically 140-feet, 150-feet thick. So there's a geological reason why they're seeing those kind of results. It would be unlikely for us to see those kind of results.

Okay. Thanks.

Thank you.

Mr. Whitehead, do you have any closing comments?

I do not. I appreciate everybody listening in. We look forward as this year goes on. We think we're making a lot of progress, and thank you for listening in.

That does conclude today's conference. Thank you all for your participation.