Gastar Exploration Management Discusses Q2 2012 Results - Earnings Call Transcript

Aug. 8.12 | About: Gastar Exploration (GST)

Gastar Exploration (NYSEMKT:GST)

Q2 2012 Earnings Call

August 08, 2012 10:00 am ET

Executives

Lisa Elliott - Vice President

J. Russell Porter - Chief Executive Officer, President and Non-Independent Director

Michael A. Gerlich - Chief Financial Officer, Principal Accounting Officer, Vice President and Corporate Secretary

Analysts

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Chad Mabry

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Gastar Exploration Second Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, August 8, 2012. I would now like to turn the conference over to Lisa Elliott with DRG&L. Please go ahead, ma'am.

Lisa Elliott

Thank you, Erin, and good morning, everyone. Before I turn the call over to management, I do have a couple of items to go over. First, a replay of this call will be available shortly by webcast on the company's IR website and a telephone replay will be available for 1 week. You can obtain the access information from yesterday's news release.

Also today's call will contain forward-looking statements. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in the company's Form 10-K and subsequent 10-Qs, which can also be found in the Investor Relations section of the website. Should one or more of these risks materialize or should underlying assumptions proven incorrect, actual results may vary materially. Today's call may also include a discussion of probable or possible reserves or use terms like reserve potential, upside or other descriptions of nonproved reserves, which are more speculative than estimates of proved reserves, and accordingly, are subject to greater risk. Information relayed on this call speaks only as of today, August 8, 2012, so any time-sensitive information may no longer be accurate at the time of the replay.

So now I'd like to turn the call over to Russ Porter, Gastar's President and Chief Executive Officer. Russ?

J. Russell Porter

Thanks, Lisa, and good morning, everyone. With me this morning is Mike Gerlich, our CFO. And as usual, I'll go through a review and update on our operations and Mike will follow up with a review our financials.

From an operational standpoint, Q2 was an excellent quarter for Gastar. We increased our production year-over-year by 87% and 18% sequentially and we exceeded the top end of our guidance for average daily production by nearly 3 million cubic feet equivalent. Second quarter production totaled 34.8 million cubic feet equivalent per day, which is the highest production rate in our company's history.

We came in near the top end of our guidance for the percentage of total production being contributed by higher value liquids, which has grown into 19%. The percentage of production from liquids was 16% last quarter and only 4% a year ago. Second quarter liquids revenues, including the oil condensate and NGLs, contributed to 40% of our total natural gas oil and NGL revenues after hedging.

All of this growth is being driven by the success of our active drilling program in Appalachia, where we're focused on our liquids rich acreage in Marshall County, West Virginia. Specifically in the Marcellus, our net production grew 49% sequentially. Appalachian production overtook Texas production for the first time with 60% of our second quarter volumes now coming from the Marcellus. Second quarter net daily production from Appalachia averaged 20.7 million cubic feet equivalent made up of approximately 14.5 million cubic feet of natural gas per day and approximately 353 barrels of condensate and 685 barrels of NGLs per day. Total liquids production is currently about 35% of Marcellus production. The Marcellus is now contributing 68% of our total natural gas oil and NGL revenues before realized hedging benefits.

Although the decline in NGL prices since the first year has compressed the economics of our Marcellus wells somewhat, as it has for the industry as a whole, the economics still remain very compelling with roughly 24% internal rate of return on the average Marcellus well based on current pricing and third-party reserve estimates. Those IRRs could improve if the liquid yields continue to increase as we have seen as we move westward on our acreage.

The quality of this play is reflected in our June 30 reserve analysis. This midyear report shows that over a 6-month period, our proved reserves grew 40% over year-end 2011 proved volumes. Keep in mind that this follows an increase of 138% in proved reserves that we reported at December 31, 2011, over year-end 2010.

Our total proved reserves increased from 120 Bcfe at December 31 to 167 Bcfe at June 30. But due to the decline in pricing, the PV-10 value of those reserves declined from $217 million at December 31 to $179 million at June 30 based on the SEC pricing formula. Despite this substantial volume growth, lower natural gas and NGL prices contributed to the need for an asset impairment charge. In the second quarter, we took a $73 million noncash ceiling test impairment, which affected our financial results in a material way. The SEC rule requires us to run our ceiling test every quarter using a 12-month average of first day of the month prices for each of the previous 12 months.

Using a NYMEX futures pricing curve, the PV-10 of the estimated proved reserves increased to $239.5 million at June 30, 2012, from $237.7 million at year-end 2011. The NYMEX futures pricing curve is more reflective of our reserve value, so we do not expect this noncash writedown to have an effect on our access to funds to execute our capital program in the Marcellus this year.

Next, let me recap our activities during the second quarter, which were focused entirely on the Marcellus. As of June 30, we had 18 gross operated horizontal Marcellus wells on production in Marshall County. We need to point out that the Wengerd 1H and 7H wells that have been producing for about 9 months were shut-in during the second quarter while we drilled 5 additional Wengerd wells from the same pad. So at quarter end, we had a total of 20 wells that were capable of producing. Our average working interest in these 20 wells was 43.7% and the average lateral length of the horizontal section was about 4,800 feet. As a general rule, our working interest in the wells we are drilling and operating this year range from 40% to 50% and the well lateral length ranges from about 2,500 feet to 6,100 feet but weighted average of about 4,500 feet. Drilling and completion costs currently average approximately $1.3 million to $1.5 million per thousand feet of lateral.

Before walking through the joint program, let me give you an update on the third-party gathering system that has constrained our Marcellus production for the past 10 months. As we've discussed before over the last several quarters, our Marshall County production volumes have been curtailed by issues with condensate handling, dehydration limitations and high line pressures on the gathering system that was recently purchased by Williams. Williams has been gradually resolving these issues. As a result of these past issues, it's been difficult to gauge the true potential of our recent completions as we haven't been able to produce new wells into a constant pressure environment or interrupted due to continued downtime related to the gathering system. We are expecting that the future wells will not be impacted by these issues.

You probably saw our recent news release regarding the mechanical failure and fire that occurred at Williams midstream central receipt point that compresses and gathers all of our operated production in Marshall County. That fire happened on June 26, resulting in an immediate shutdown of production operations. There were no injuries or damage to Gastar's properties or facilities, although Williams did sustain some damage to a portion of its facilities. They had the CRP repaired and back online on August 3, and we resumed production the same day. The downtime cost us about 181 MMcfe of production over an 8-day period that will impact our third quarter results. Williams is building a new CRP at the Burch Ridge well pad, and they will build an adequate dehydration capacity and compression to ensure appropriate line pressures when we bring on additional production from our wells that are currently being drilled and completed. The Burch Ridge CRP is scheduled to be operational before the end of this year. If commission of that facility is delayed, we may have to restrict our production in the fourth quarter of 2012.

Now looking at our Gastar operated drilling and completion activity in second quarter, starting with our operated wells in Marshall County. As we mentioned on the last call, early in the quarter, we put 5 Hendrickson wells on sales. In late June, we placed the 3 well Accettolo pad on production. These 8 wells are performing as expected and are currently producing about 1.9 million cubic feet, approximately 88 barrels of condensate and 103 barrels of NGLs each per day.

Liquids production on these wells continues to be about 38% of the wells' total production. In May, we began fracture stimulation on the 5 wells on the Burch Ridge pad. In July, we began fracture stimulation on the 4 Wayne wells. All these wells are in the western end of our Marshall County leasehold with laterals that are a bit longer, about 5,400 to 5,500 feet. Earlier this week, we began the initial flowback operation in the 5 Burch Ridge wells that were recently completed. After 3 days of flowback, the 5 wells are currently producing at a combined gross rate of 12.1 million cubic feet of gas a day, 1,050 barrels of condensate and 160 barrels of NGLs per day at approximately 1,600 PSI tubing pressure. The 27% condensate yield from these wells is the highest condensate rate that we have seen so far in Marshall County. The combined liquids yield condensate NGLs from these wells of 46% is also the highest we've seen.

In addition, top-hole drilling operations began during the second quarter in our Wengerd and Shields leases. We have spud the Wengerd 3H and 5H and 3 additional Wengerd wells are planned for the same pad. We expect to drill and complete and commence production from 7 Wengerd wells, including the first 2 that are now shut-in by late November or early December.

In the second quarter, we drilled the top-hole portion only on 8 Shields wells and we plan to drill the remaining top holes in October. Horizontal drilling operations are scheduled to commence in January on the Shields pad and continue through the winter season. We plan on frac-ing all 10 wells, and then turning the pad to sales. Based on the current schedule, the Shields pad should be on sales by August 2013. The lateral section of the Shield wells will average about 2,600 feet due to surface location and lease configuration constraints. We're continuing to use a shallow rig to drill the top-hole portion of our wells and a second larger rig to drill the laterals, which probably saves us about $150,000 per well and drilling rig costs first using the larger rig for both the vertical and horizontal sections.

Since the end of the second quarter, we've also begun top-hole drilling on the 4-well Lily drilling pad. These wells should be completed and on production by the end of the year with an average length -- average lateral length of 5,200 feet. In September, we plan to commence top-hole drilling operations on the 4-well Addison pad with horizontal drilling to commence in November. These wells will have an average lateral of 5,200 feet and are scheduled to be completed and on production in April 2013. Based on the drilling activity I've just described, we would expect to have 34 operated producing wells on sales at year-end 2012 with the 4 Lily wells scheduled to be on production in early January 2013.

Now a quick update on our nonoperated Marcellus wells. In Marshall County, we participated in 1 additional nonoperated well in the second quarter. We now have a total of 4 nonoperated wells on production in that county. We have a 21.4% working interest in these nonop wells with an average lateral length of about 4,200 feet. All 4 wells are on production and are producing at expected rates for the area. In Butler County, Pennsylvania, we have a 19.2% nonoperated working interest in 7 producing wells operated by Rex. No additional wells are planned from that pad.

Looking at East Texas. We are continuing to defer any new drilling or significant workover and recompletion activity in the Hilltop area due to continued low natural gas prices. Almost all of the zones we have produced so far in East Texas are strictly dry gas and the economics are so much more compelling in the Marcellus that we're going to keep our spending focus there for the foreseeable future. As we've said in previous calls, we will continue to monitor the results of wells being drilled and completed by EnCana and EOG, targeting oil formations near our acreage. But we currently have no plans for drilling and exploration oil well test this year.

Regarding our Mid-Continent activity. We are continuing to build a lease position in our Mid-Continent oil play. We added about 4,000 acres during the second quarter. And at quarter end, we held approximately 20,300 gross or 9,900 net acres. Since the quarter end, we have increased our acreage position to 22,500 gross or 11,250 net acres. Our target within this initial area is approximately 25,000 gross acres.

In late July, drilling began on the first of 3 wells we have planned on this acreage before the end of this year. These are nonoperated wells and are estimated to cost about $4.3 million gross with a horizontal lateral of about 4,200 feet. We are paying 62.5% of that to earn a 50% interest. These terms apply to the first 4 wells we plan to drill in the initial prospect area. For the fifth well and beyond, on the current prospect area, we will pay only for our 50% working interest and no promote. We hope to complete this first well some time in September and spud the second well by early October and the third well by December.

At this point, I'll turn it over to Mike to go through the numbers, and then I'll rejoin the call.

Michael A. Gerlich

Thanks, Russ, and good morning, everyone. I'm going to assume that everyone had a chance to review our second quarter earnings release that we filed yesterday after the close of the market. So I'll just highlight a few key items.

Our natural gas oil and NGLs revenues increased 31% from a year ago to $11.1 million due to our significantly higher volumes of condensate and NGLs from the Marcellus Shale play. That production growth more than offset the impact of decline in natural gas production in East Texas and the substantially lower commodity prices. Our blended average sales price before the impact of hedges declined 36% year-over-year while the price after the impact of our hedging program declined 30%.

Company-wide, our blended average price per Mcfe with hedging was $3.51. Without realized hedging, our total company price per Mcfe was $2.56. As you can see, we have continued to benefit from our active hedging program and continue to have a significant portion of our production hedged for the balance of 2012. Declining natural gas prices over the past 12 months was the main contributor to the $72.7 million ceiling test impairment. And our net loss for the second quarter on a reported basis was $74 million or $1.17 per share.

If you exclude the noncash impairment charge and the $2.8 million unrealized hedging gain, our adjusted net loss would've been $4.1 million or $0.06 per share. That compares to an adjusted net loss of $377,000 or $0.01 per share for the second quarter of 2011. Our cash flow provided by operations before working capital changes was $0.09 per diluted share compared to $0.05 per diluted share last year and $0.06 per diluted share last quarter after adjusting for litigation expense.

As Russ mentioned earlier, the second quarter average daily production increased by 18% from the prior quarter and by 87% from a year ago to 34.8 million cubic feet of gas equivalent. Second quarter 2012 daily production exceeded our guidance of 29 to 32 MMcfe per day due to declining third-party Marcellus gathering system downtime and additional production benefit from lower pipeline pressures resulting from the addition of compression in mid-May. As expected, our Marcellus gathering system was shut down for 8 days during the second quarter to accommodate the installation of additional compression and dehydration equipment. Based on the precompression production rates, this downtime negatively impacted second quarter results by 147 MMcfe a day or 1.6 million equivalents per day.

For the third quarter, we expect total company production to average between 35 and 37 MMcfe per day. That includes the shutdown in August related to prepares needed at the third-party gathering system, as Russ previously discussed. We estimate that total net production loss during the 8 days is approximately 181 MMcfe or the equivalent of 2 million cubic feet equivalent per day for the third quarter of 2012. Liquids as a percentage of total company production is expected to increase from 19% in the second quarter to 20% to 24% in the third quarter as we continue to bring on new Marcellus wells and experience natural declines at our East Texas dry gas wells.

Now looking at the results of our hedging program. For the second quarter, approximately 87% of our natural gas production was hedged, which increased our revenue by approximately $2.3 million. Approximately 74% of our liquids production was hedged, resulting in increase in liquids revenues of approximately $674,000. As of June 30, we have hedges covering approximately 25,000 MMBtu per day of natural gas production for the remainder of 2012 in the form of costless 3-way collars, put spread hedges and call spread hedges.

Additionally, for the remainder of 2012, we have fixed price swaps for 600 barrels a day of crude at about $102 per barrel and fixed price swaps for 200 barrels a day of NGLs at $52.50 per barrel. A portion of our crude hedges are utilized to hedge the heavy NGL components of butane, isobutane and pentanes, which currently comprise approximately of 40% of our NGLs production. Complete details about our hedge positions as of June 30 are available in our 10-Q, which was filed yesterday.

As we continue to increase our oil and NGL production, we will also look for opportunities to enhance our liquids hedging position to support our capital program. We did not add any new oil or NGL hedges in the second quarter due to lower commodity prices.

Moving onto some of the key expense items in the second quarter and our guidance for the third quarter. Production taxes have increased as expected primarily because our Marcellus production is not exempt from production taxes, while historically, our East Texas production has been exempt under Texas tight sands credit. Lease operating expense was $1.6 million, which was significantly lower than our earlier guidance of $2.2 million to $2.5 million. This is mainly because of lower-than-anticipated East Texas workover cost and lower water disposal expense in the Marcellus that we've been able to recycle a greater portion of our water from well-to-well.

Lease operating expense per Mcfe was down substantially to $0.49 in the second quarter versus $0.90 in the second quarter and $1.10 a year ago. That was $0.90 in the first quarter and $1.10 a year ago. Excluding workover cost, our LOE per Mcfe would have been $0.46 versus $0.77 in the first quarter of 2012 and $1 in the second quarter of last year. For the third quarter, we expect total LOE to be in a range of $1.9 million to $2.2 million.

DD&A in the second quarter was $2.20 per Mcfe or $0.09 higher than the first quarter per Mcfe cost. The recognition of the $73 million impairment expense should decrease DD&A per unit cost to approximately $1.80 to $1.90 per Mcfe for Q3. Transportation, treating and gathering expenses were in line with previous quarterly guidance. For Q3, we expect transportation, treating and gathering expenses to again be in the range of $1.2 million to $1.3 million. This expense should continue to be relatively range-bound in area for the remainder of the year under current marketing and reporting.

Cash G&A expense for the second quarter was $2.2 million, slightly below the guidance range we provided last quarter. Noncash stock compensation expense was $954,000, which was slightly higher than the guidance due to a true-up of forfeiture rates related to recent restricted share vestings. For the third quarter, we expect cash G&A of $2 million or $2.2 million and noncash G&A to between $700,000 and $800,000.

Moving now to the balance sheet. At June 30, we had cash and cash equivalents of $8 million and $47 million outstanding on our revolving credit facility for a net debt position of $39 million. Currently, our net debt position is $45 million. The next redetermination of our borrowing base is scheduled for early fourth quarter. At this time, we anticipate a modest increase in the borrowing base as additional proved developed producing wells are added to offset any product price declines. We continue to anticipate a more significant borrowing base increase early next year based on the year-end reserve report. We had a net working capital deficit at the end of the second quarter of $25.7 million, which was up $6.9 million from the prior quarter. Out of the working capital deficit, advances from nonoperating partners was $25.4 million, an increase of $7.1 million from the first quarter 2012 balance.

During the second quarter, we issued another 405,368 Series A preferred shares for total net proceeds of approximately $7.7 million. Post quarter end, we issued an additional 253,842 shares for $4.2 million, bringing an inception-to-date issuances to 3.64 million shares for net proceeds of $70.5 million. We have approximately 400,000 preferred shares remaining to issue, which we estimate should be completed no later than early fourth quarter.

Looking at capital expenditures. During the second quarter, we spent a total of $32.1 million resulting in year-to-date capital expenditures of $69.4 million. For the remainder of the year, we expect to spend an additional $65.5 million in capital, including $51.1 million in the Marcellus Shale, $10.5 million in the Mid-Continent, $1.5 million in East Texas and $2.4 million for capitalized interest and other cost.

Now I'll turn it back over to Russ for final comments. Russ?

J. Russell Porter

Thank you, Mike. I would like to reiterate how pleased we are with continued progress we're making in our Marcellus program. Improvements in line pressure and dehy capacity on the pipeline, combined with new wells coming on line, should allow us to increase production rates in the third and fourth quarters. We're also very pleased with the reserve additions we've realized since the end of last year. It's unfortunate that low gas prices and the SEC pricing methodology we are required to use to report reserves and PV-10 value are camouflaging our success. But as liquids cut of our total production increases, that should translate into very tangible growth and shareholder value and improvement in the bottom line.

Based upon third-party core analysis and engineering studies we've recently reviewed, we believe that our acreage in Marshall and Wetzel Counties is among the most productive for high-value NGLs and condensate in the Marcellus play, making the economics of our program very attractive. We look forward to the results of our first well in the new Mid-Continent oil play as we continue building a lease position, and we believe the play has a potential to further transform the asset portfolio and the production profile of our company.

We're prepared to continue executing our Marcellus program as planned for the rest of this year and into next year as well. That concludes our prepared remarks this morning. And we'll open up the call to questions now. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of the Kim Pacanovsky with MLV and Company.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Just a question on the Burch Ridge CRP. Has the construction actually started on that? And if not, do you -- can you just narrow the timeline down more at least to what Williams is telling you?

J. Russell Porter

We've got all of our lines built to the location. And there's been dirt moved on the location. Williams has not started actual construction yet, but they're along the path on planning. Our original plans earlier this year called for that to be ready by the end of August, early September. Now we're hoping it could be probably November, hoping it doesn't get pushed to December.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. And so the wells that you'll be adding this year or by year end, if that facility is up and running, would be the 5 Burch wells, the 7 Wengerd and the 4 Wayne. Is that correct?

J. Russell Porter

No. The Wengerd wells will go into the existing Corley CRP.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

No. I just mean end of year, not into this CRP, into the Burch CRP.

J. Russell Porter

Okay. Then you're going to have to repeat the question because...

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. So by year end, we are looking to see 7 Wengerd wells, 5 Burch Ridge wells, if that facility is up and running, and 4 Wayne wells?

J. Russell Porter

That's correct. Yes. But the 5 Burch Ridge wells are already producing. We ran a temporary line from those wells over to our Corley CRP. So we have those wells already on production, they're just -- [indiscernible] a little bit as evidenced by the higher tubing pressure.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Right. Okay. And then just one last question, I'll turn it over to somebody else. You said that you can't produce new wells into a constant production environment so you're not really able to, I guess, get apples-to-apples IP rates. But can you just make some general comments on what you're seeing with the new wells that have come online? And maybe make a comparison -- if you can even make a comparison to some of your early results if you've changed things in the fracs, et cetera?

J. Russell Porter

I guess, the general comment we can make is that as we've continued to move westward on our acreage, we're definitely seeing higher NGL and condensate yields. The wells are performing basically as we expected. What we can't give you is an apples-to-apples IP comparison on these because the previous wells have been produced into such a hectic environment, if you will, on run time with the pipeline. Going forward, we hope to get that issue behind us. But I can tell you that right now, we're really not seeing very many detrimental effects from that because what that probably resulted in by having those higher line pressures were some restrictions on our production, which as we've worked with some of the third-party engineers and such, looks like those restrictions probably ended up lowering our decline rates and extending our EURs some. So it's been -- it hasn't been as clean an operation from a midstream standpoint as we would have liked. But our execution on drilling and frac-ing the wells has been very good. We're seeing excellent per well EURs, very good flow rates when we have the midstream capacity. So in general, we're very pleased with the effort that our team has put together up there. And we certainly think that it's being demonstrated by the reserve growth.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

So the production coming in above your guidance, was that actually due to better wells or just a bigger cushion you put in there because of the midstream difficulties?

J. Russell Porter

It was a combination of primarily less downtime than we had projected on the [indiscernible], and then some better well performance.

Operator

[Operator Instructions] And our next question comes from the line of Chad with KLR Group.

Chad Mabry

Looking at the midyear reserve report, guys, obviously some really strong growth there. I was wondering if you could help us quantify maybe the negative revisions there as well as kind of what you were able to add from your Marcellus program there.

Michael A. Gerlich

Really on the negative revision, the only place we had negatives were really in East Texas. And those were primarily related to the lower pricing and economic limits. And that was probably in the range of just a couple of Bcfs. So everything else that you've seen change-wise after you back in really is coming from our Marcellus activity.

Chad Mabry

Okay, got it. And then could you -- any way you could provide kind of per well bookings from the Marcellus in the report?

J. Russell Porter

We don't have that right here in front of us. And it's -- there's not a lot of variation between the wells. 2 wells with the same lateral length are basically getting the same type reserves. But we're not prepared to provide a per well on this call.

Chad Mabry

Got it. Okay. And then kind of shifting over to the Mid-Continent oil. When do you think we'll be able to -- or I guess, you'll be able to provide some additional color on kind of what play you're chasing there? Obviously, it sounds like you're completing that first horizontal well next month. So I would assume that you'll be kind of prepared to discuss that next month?

J. Russell Porter

Well, our plan all along has been to assemble the acreage position as inexpensively as possible, get the first well drilled and completed. And then if we've got our acreage position assembled to meet our initial targets, then we'd be ready to talk about the play. We're not trying to make this more dramatic or anything than it needs to be. It's just we're trying to build a position without getting a lot of competition in there. As it stands right now, we hope to be in a position to discuss the play in detail on our third quarter conference call.

Operator

And our next question comes from the line of Patrick Rigamer with Iberia Capital Partners.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

I was wondering -- I hate to make you repeat yourself. But could you go over those numbers on the Burch Ridge again? I didn't -- it was 12.1 million on gas. And then what was condensate and NGLs?

J. Russell Porter

12.1 million cubic feet a day, 1,052 barrels of condensate a day and 660 barrels of NGLs per day.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Okay. And that was from 5 wells?

J. Russell Porter

From 5 wells. And that was after 3 days of flowback and with a 1,600 pound flowing tubing pressure.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Okay. And then you've got the central machine point coming online later this year. But is there any way we can get kind of forecast exit rate? Or is it too early to tell?

J. Russell Porter

There's just too much variation we have to build into it, Patrick. As we start to see the downtime decrease, which I'm pretty confident we'll see as the year progresses, then we may be in a position to give you a better estimate on exit rates. A lot of it will have to do with whether that Burch Ridge CRP gets online before year end or not. And then as we stated, right after the end of the year, we'll bring on 4 more wells hopefully in January. So what's important to us is that by the time we get to our next borrowing base redetermination, we're going to have 38 wells producing and have really some additional material reserve growth and proved reserves. So that's really what we're focused on.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Okay. And then you're using the microseismic in the Marcellus. Is that something you're transferring to the Mid-Continent? Or are you doing any extra science there with these early wells?

J. Russell Porter

We haven't installed any sort of microseismic array in the Mid-Continent play. At this point, it doesn't look like we would need it. There is a lot of well control around that area. As we were going into the Marcellus play in Marshall County, there was really almost no well control and very little known about the rocks so that's why we decided to make the investment with the microseismic. And it looks like it's certainly been a worthwhile endeavor for us.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Okay. So then does that mean that you feel that the acreage in the Mid-Continent is somewhat derisked or...

J. Russell Porter

Well, our opinion is it's going to derisk by the thousands of vertical wells that are produced in the area. And like we've said before, we're just going into a conventional reservoir, where you've had vertical development, applying modern horizontal drilling and completion techniques and getting recoveries that make the wells very economic. So it's really, from a geologic standpoint, very, very low risk. We know the oil is there. It's really just an execution exercise to getting the wells drilled and completed.

Operator

And that does conclude today's question-and-answer session. I would like to turn the call back to Mr. Porter for any closing remarks. Please go ahead.

J. Russell Porter

All right. Thank you, everyone. We appreciate your time this morning. And as usual, if you've got any questions or follow-up, you can contact myself or Mike here at our office.

Operator

Ladies and gentlemen, this does conclude today's conference call. If you'd like to listen to a replay of today's conference, please dial (303) 590-3030 and enter access code 4552855#. Thank you for your participation, and have a great day.

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