Ranger Oil Corp (ROCC) 2014 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2014 earnings call.

(Operator Instructions)

As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Mr. Baird Whitehead, President and CEO. Please go ahead.

Thank you, Kate. I would like to welcome you to Penn Virginia first-quarter 2014 conference call. I'm joined today by members of our management team, including: John Brooks, our Chief Operating Officer; Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our Chief Financial Officer; and Jim Dean, our Vice President of Corporate Development. Prior to getting started, we would like to remind you of the language in our forward-looking statement sections of the press releases issued yesterday, as well as our Form 10-Q, which was filed last night.

To kick things off, we continue to execute on our Eagle Ford strategy, posting record oil production, along with a strong cash flow and cash margins. We also, as importantly, continue to high-grade our drilling program going forward, based on our overall results to date, so as the sweet spots we continue to find can be further exploited as time goes on. Some of the highlights for the first quarter include production of 21,133 barrels of oil equivalent per day, up 6% from the fourth quarter of 2013. Eagle Ford Shale production of 15,152 barrels of oil equivalent per day, up 15% from the fourth quarter. Oil production for the Company was a record 11,955 barrels of oil per day, an increase of 7% over the fourth quarter, with an acceleration of production growth expected as the year progresses.

Also in the first quarter, our cash margins remained strong, with a cash margin per barrel of oil equivalent of $54, up from $48 in the fourth quarter. Product revenues were $70 per BOE, compared to $64 per BOE in the fourth quarter, with 86% of the product revenues coming from oil and NGLs.

Lease operating expenses decreased to $5.47 per BOE, from $5.74 per BOE. Gathering, processing and transportation expenses decreased to $1.56 per BOE, from $1.76 per BOE. Recurring general and administrative expenses decreased to $5.21 per BOE, from $5.93 per BOE. And adjusted EBITDAX was $94 million, up 11% from $84 million in the fourth quarter, and above our expectations.

During the first quarter, we increased our Eagle Ford lease position to approximately 125,300 gross, and 85,900 net acres. We added approximately 6,400 net acres in the Eagle Ford, at an average cost of approximately $3,000 per acre. We continue our aggressive Eagle Ford leasing effort at these attractive acquisition costs, as we march toward our minimum 100,000-acre position that we communicated in the past.

We now estimate that we have a remaining drilling inventory of approximately 1,510 drilling locations, a 34% increase from the 1,125 locations we previously have communicated. This is based on our ongoing leasing effort, the positive results of our down-space drilling program, and now the encouraging results of the recent well-housing completion in the upper Eagle Ford. Of this total, 1,035 of these locations are lower Eagle Ford locations, and 475 are upper Eagle Ford locations. This new estimate does not currently assume any overlapping inventory from the upper and lower Eagle Ford intervals, which may represent as many as 400 additional locations on existing acreage, if we can confirm over time that, in fact, the upper and lower are separate reservoirs.

We provided in our press release the details of our initial results from our Welhausen pad located in the southeastern part of our acreage in Lavaca County. We drilled an upper and lower Eagle Ford side by side, and completed each zone accordingly, with the Welhausen being completed in the lower and the A well completed in the upper. We are very pleased about the initial results of each. Based on the initial production rates and pressures, a case could be made that they are acting like separate reservoirs and not in communication, but additional time and production history will be necessary to confirm this hypothesis.

The initial production rate in the press release from the upper was 2,165 barrels of oil equivalent per day, with a very high flowing pressure. The adjacent lower tested at 1,536 barrels of oil equivalent per day, and it also had a very high flowing pressure. In addition, we have recently completed and brought online a Martinsen #2 well, [a third] of the Eagle Ford test well approximately two miles to the north of the Welhausen pad. John Brooks will give you some more detail on all these wells in a few minutes.

As already mentioned, longer-term testing will be necessary to fully understand the upside associated with the upper Eagle Ford, but we remain very positive about the play and that it could contribute significantly to overall production reserve growth over time. At this time, we have not adjusted our drilling program in order to take into account, which at this time is considered excellent news about the upper Eagle Ford Shale. This may, in fact, occur as the year progresses; so, as always, we will drill the best opportunities in front of us.

Through March 31, we estimated $37 million for lease-hold acquisitions. As our ongoing leasing activity remains successful, we are increasing our leasing capital expenditures guidance for the year by $13 million to $20 million. Otherwise, our previously reported guidance remains unchanged.

As we have disclosed in the past, we sold our Eagle Ford Shale natural gas gathering assets for a total price of approximately $100 million; $96 million net to our interest. Currently, we have three other divestiture processes underway, including our assets in Mississippi, Oklahoma, and the rights to build an oil gathering system for our Eagle Ford Shale operations. We have received bids on all three, are currently evaluating or negotiating with potential buyers, and will announce any transactions if and when any agreements have been signed. This is consistent with our commitment to actively manage our portfolio, and divest of our non-core assets to fund our ongoing operations in our most promising asset, which, of course, is the Eagle Ford.

To summarize, it is clear that we continue to operationally execute on our strategy to build value in the Eagle Ford, not only by drilling excellent wells, and converting PUDs, prob's and [possibles] to PDPs, but also by continuing to expand our Eagle Ford lease-hold position.

A fairly straightforward statistic points out our growth in value: If you buy an Eagle Ford acre for about $3,500, drill it with a $9.6-million well, that acre, net of investment, is now worth anywhere from $80,000 per acre to $100,000 per acre, depending on spacing. I think you would consider that a very attractive arbitrage.

And at this time, I would like to turn the phone call over to John Brooks, so he can give you some additional operation to detail for the first quarter.

Thank you, Baird, and good morning. For 18 wells that we turned in line in the first quarter of 2014, our average rates were 1,080 barrels of oil per day and 2,004 Mcf per day, or a combined 1,415 BOE per day. So, our well results continue to be strong.

Our average well cost came in at a little over $9 million, with an average of 24.6 frac stages per well, which, given our mix of mostly three-string wells, is a positive performance marker in continuing to reduce total well cost. As we've stated, Penn Virginia is running six rigs in the Eagle Ford, though technically we're actually running seven rigs, counting the smaller spudder rig that is used to pre-set surface casing on the pads for the big rigs.

As we've transitioned almost completely to pad drilling, we've developed a strong inventory of wells to complete. As of March 31, we had 19 wells completing or waiting on completion, as shown in the release. Currently, though, we have 10 wells flowing back from recent fracs, 5 being completed, and another 8 waiting on completion. So, we're making progress in getting caught up on our completions. Our stimulation costs are running about $120,000 to $125,000 per stage, and we continue to ramp up total sand volumes to roughly 1,500 pounds of proppant per lateral foot.

We continue to make real progress in being an efficient and productive operator. On the drilling front, the aforementioned spudder rig, which pre-sets surface casing for our big rigs, saves us an estimated $70,000 and 56 hours of big rig time per well. The positive effects of this cycle time compression have yet to be fully realized, but we should start seeing the benefits roll through later in the second quarter and beyond.

Additionally, in China, which requires three strings of casing, we further optimized our walking rigs to batch set the intermediate casing on the pre-set surface casing, and then drill and case the laterals without having to repeatedly lay down and pick up drill pipe. This saves us, on average, an estimated $46,000 and 14 hours per well.

Another recent development where we've improved on our costs is in our drilling mud. Penn Virginia now provides its own drilling fluids and fluid engineering services on five of our six big rigs. On average, running our own mud, and, in effect, buying mud products wholesale saves us about $57,000 per well, or equivalent to about 20%.

Now, I would also like to bring you up to date on our upper Eagle Ford delineation results so far, and let me start by saying that we have established that the upper Eagle Ford works, and works very well. We are still evaluating whether it is a separate reservoir from the lower Eagle Ford, but we are encouraged by our recent results. Our first upper Eagle Ford well, the Fojtik #1H was completed last Spring, with a relatively short lateral, 4,200 feet, and 17 stages; and it IP-ed at about 1,200 BOE per day, and has produced 96,000 BOE in 12 months. It was drilled as a single well in its unit, with no other nearby production. And at year-end 2013, it was estimated to have an AUR in excess of 390 MBOE.

So, following up on that, our most recent test is our Welhausen unit, which is our deepest down-dip test of the Eagle Ford in Lavaca County, and lies to the southeast of our historical Shiner development. The Eagle Ford occurs between 12,500- and 13,000-foot TVD at this unit. And, to our knowledge, there are no other Eagle Ford completions in close proximity to this pad. The Welhausen two-well pad was drilled and completed with the Welhausen A2, testing the upper Eagle Ford, and the Welhausen B1, completed in our traditional lower Eagle Ford landing zone.

They were each drilled 330 feet away from the unit line, which was straddled by the two well bores, so they were a total of 660 feet apart. The A2 completion, the upper Eagle Ford test, consisted of a 6,487-foot lateral, with 26 stages, treated with 9.9 million pounds of proppant, for an average of 1,526 pounds per foot of the lateral. The B1 completion, the lower Eagle Ford test, consisted of a 5,905-foot lateral, with 26 stages, treated with 7.9 million pounds of proppant, for an average of 1,337 pounds per foot of lateral.

Following the release of the frac equipment, coil tubing was used to drill out the plugs, and for the primary clean-out procedures. The plugs on the B1 were all drilled out. On the A2, the last eight plugs towards the toe of the lateral were not initially drilled out.

The wells returned in line to test equipment on March 20, with first gas sales on March 21. Peak 24-hour rates for the two wells since then are as follows. In the Welhausen A2, we have 1,086 barrels of oil per day, and 6,475 Mcf per day, for 2,165 BOE per day, with 595 barrels of water per day at 4,600 PSI on a 22/64 choke. The Welhausen B1 in the lower Eagle Ford tested at 807 barrels of oil per day, 4,372 Mcf per day, with a combined rate of 1,536 BOE per day, at 879 barrels of water per day, 4,372 PSI on a 20/64.

Both wells required secondary clean-out operations. And during that secondary clean-out operations, we were also able to drill out the remaining eight plugs on the A2 upper Eagle Ford well, allowing all stimulated stages to then contribute to the well bore. Both wells were returned to production on May 7, and the rates on the A2 reflect higher production performance following the drillout of its remaining plugs in the secondary clean-out operation.

Oil gravity for both wells, uncorrected for temperature, is 55 degrees API. Corrected for temperature, it's 51 degrees and 53 degrees. The GORs are 5,962 SCF per barrel for the upper Eagle Ford test, and 5,418 SCF per barrel for the lower Eagle Ford. And although we're seeing higher gravity and higher GORs, it appears that we're still in the volatile oil window. We have approximately a 94% working interest in the Welhausen unit in these two wells.

Our next upper Eagle Ford test is on our Martinsen pad, where we drilled the Martinsen #2H and 3H. The #2 well was drilled and completed in the upper Eagle Ford, and is a 400-foot direct offset to our Martinsen #1, which is one of our best lower Eagle Ford wells. The Martinsen #1 IP-ed at 1,878 BOE per day in March 2013, and has cumulative production of over 101.8 in barrels of oil, and 381 in Mcf of gas, or over 165 in BOE in the last 13 months. The Martinsen #3 was drilled and completed in the lower Eagle Ford, and was another 400-foot direct offset to the #2 well, and therefore, 800 feet away from the Martinsen #1, the original well in the unit.

The Martinsen #2 has a lateral of 5,891 feet and 27 stages, and was fracked with 10 million pounds of proppant, for an average of 1,700 pounds per foot of lateral. The Martinsen #3H has a 4,462-foot lateral and 21 stages, and was fracked with 6 million pounds of proppant, for an average of 1,336 pounds per foot of lateral. Both have been cleaned out, had their plugs drilled out, and turned to test. And it's still early in the flowback stage, and both wells continue to clean up, but the results appear to point toward the upper Eagle Ford behaving independently of the lower Eagle Ford, as the pressures in the upper Eagle Ford well are about 2,000 PSI higher. We have an approximate 94% working interest in the Martinsen unit.

So, to summarize our upper Eagle Ford results so far, we have one well, the Fojtik, our initial upper Eagle Ford well, drilled by itself in a new unit; two wells drilled 660 feet apart in the new unit, with one in the upper and one in the lower; and another upper Eagle Ford well drilled between a mature lower Eagle Ford well and a new lower Eagle Ford well. In all cases, the upper Eagle Ford has worked, and has demonstrated that it can yield IPs at the high end of all our Eagle Ford activity.

Determining if it acts as a separate reservoir from the lower Eagle Ford will take more tests and additional time, but, again, we are encouraged by our most recent testing. Later this year, we plan to have another test in our RBK unit. Preliminary plans are for the RBK unit to be a four-well pad, with two wells in the upper Eagle Ford and two wells in the lower Eagle Ford, in a staggered offset chevron pattern, with each lateral spaced 400 feet apart in plan view.

Based on these positive results in the upper Eagle Ford, we've added new locations in our drilling inventory for the play. Since we have not yet conclusively determined whether or not they act as separate reservoirs, we haven't yet counted any locations that would overlap with lower Eagle Ford locations, even though we do have some results in that regard. Our total Eagle Ford location inventory now stands at approximately 1,500 locations, with about 470 of those in the upper Eagle Ford.

Moving on to other recent developments: On our Rock Creek Ranch Wyatt pad, we recently drilled and completed four wells, the Rock Creek Ranch Wyatt 1H, 2H, 3H and 4H. This is in our joint venture with Marathon in Gonzales County. All wells were drilled and completed in the lower Eagle Ford. The 1H has a 7,055-foot lateral, 32 stages, and was fracked with 10.8 million pounds of proppant. The 2H has a 6,357-foot lateral and 29 stages, and was fracked with 9.8 million pounds of proppant. The 3H has a 7,202-foot lateral and 33 stages, and was fracked with 10.8 million pounds of proppant. And the 4H has a 6,809-foot lateral, 31 stages, and was fracked with 10.4 million pounds of proppant. Proppant volumes for this four-well pad averaged a little over 1,500 pounds per foot of lateral.

For the sake of comparison, we drilled out all the plugs on this four-well pad with a work-over rig and jointed pipe, as opposed to coil tubing. It took a little bit longer, but we got all the plugs drilled up with a higher degree of mechanical efficiency than coil. The cost may come in slightly higher, but the jointed pipe gives us a higher degree of confidence in getting all the plugs drilled out in wells with longer laterals. We have not yet IP-ed these wells, since it's early and they are still cleaning up, but the four-well pad as a total is making about 5,000 BOE per day, with 88% of that oil. We have an approximate 47% working interest in the Rock Creek Ranch Wyatt unit.

That concludes my operational update. And at this time, I'll turn it over to our CFO, Steve Hartman.

Okay, thanks, John. Good morning. I'll start with the comparison of our first-quarter financial results to our fourth-quarter 2013 results. Total revenue for the quarter was $189.9 million.

We realized a $68-million gain on the sale of our natural gas gathering system, which closed in January. $56.8 million of that gain is recognized as a gain on sale this quarter. The remaining gain will be amortized into other revenue over the next 25 years. We received net proceeds of $96 million from the $100-million sale price.

Product revenues for the quarter were $133.2 million, or $70.01 per BOE, a 14% increase over the fourth quarter. Adjusted EBITDAX, a non-GAAP measure reconciled on page 9 of the release, was $93.8 million, 11% higher than the $84.4 million reported in the previous quarter. Direct operating expenses, excluding share-based compensation, were $30.6 million, or $16.08 per BOE, compared to $27.8 million, or $15.09 per BOE, in the previous quarter.

In general, our expenses were better than anticipated. Lease operating expense was lower, at $5.47 per barrel, compared to $5.74 per barrel last quarter. Gathering, processing and transportation expense was lower, at $1.56 a barrel, compared to $1.76 per barrel. The decreases in LOE and gathering expense are particularly noteworthy, because our new Eagle Ford gas gathering and gas lift agreement went into effect this quarter.

Recurring G&A expense was also lower, at $9.9 million, or $5.21 per barrel, compared to $10.9 million, or $5.93 per barrel last quarter. These decreases were offset by a quarter-over-quarter increase in ad valorem tax. We recognized a $3.6-million credit in the fourth quarter, and with that credit normalized out, our direct operating expenses were improved this quarter.

Capital expenditures for the quarter were $182 million, compared to $150 million in the fourth quarter. The increase is primarily due to drilling and completion costs, which were $135 million, compared with $104 million the previous quarter. However, this was lower than we expected for the first quarter, consistent with the higher number of wells waiting on completion. As John mentioned, we expect we'll catch up the completions in the second quarter. Lease-hold acquisition was $37 million for the quarter, compared with $40 million the previous quarter.

Cash margin per BOE, as defined in our earnings release, was $53.93 per BOE, compared to $48.48 last quarter. Improvement in our cash margin per barrel continues to be driven by the strong profitability of the Eagle Ford program. Our cash margin per barrel in Eagle Ford, excluding allocated G&A, was about $72 in the first quarter.

Our adjusted net loss attributable to common shareholders was $7.9 million, or $0.12 per share, compared to $6.7 million, or $0.10 per share, in the fourth quarter. The primary driver for the higher-than-anticipated loss is our share-based compensation expense, specifically the liability classified awards, which were $5.9 million in the first quarter. Excluding the share-based compensation, our adjusted net loss is $0.06 per share.

The liability classified awards are the performance-based restricted stock units described in our proxy statement. Recognizing this expense is similar to a mark-to-market type of calculation; the value of these units fluctuates as a function of our stock price and our performance relative to a peer group. In this case, the higher-than-expected valuation increase was driven by the appreciation in our stock price over the quarter, from starting at $9.43 per share and ending the quarter at $17.49 per share. There has been no cash paid out to date on these awards, and no cash will be paid out in 2014. The first vesting date is in February 2015.

Moving on to capital resources and liquidity: At quarter end, we had $190 million outstanding on our credit facility, and $10 million of cash on hand. Our borrowing base at quarter end was $425 million. When we recently completed our Spring re-determination, our borrowing base is now $475 million, which is $50 million higher than our borrowing base determined last Fall. Our next borrowing base re-determination will be in October, later this year.

Our leverage at quarter end was 3.6 times total debt to pro forma adjusted EBITDAX, compared to our leverage at year end, which was 3.7 times, and to our credit facility covenant, set at 4.5 times. Pro forma adjusted EBITDAX at quarter end for the trailing 12-month period, as defined in our credit agreement, was $353 million, which is higher than the $342.4 million we recorded at year end.

Now, on to our 2014 guidance update, which is detailed on page 10 of the release: Our guidance does not include the potential sale of any non-core assets. If and when we sell these assets, we will update guidance. As Baird mentioned, we are raising our CapEx guidance by $13 million to $20 million, to $595 million to $653 million, based on the success of our leasing activity. We are reaffirming our drilling and completion capital at $510 million to $540 million, to fund the six-rig program.

We are reaffirming our production guidance at 9.1 to 9.8 million barrels of oil equivalent. Although our first-quarter production was slightly below our forecast, we think we'll catch up the production by the third or fourth quarter, as we bring online the wells that have been waiting on completion. These wells are in our most productive areas, so we expect a sharp production increase toward the end of the second quarter and into the third quarter.

We are reaffirming our operating expenses and G&A at their current levels, with the exception of share-based compensation. We are increasing that guidance to reflect the higher liability-based share valuation. Adjusted EBITDAX is also reaffirmed at $440 million to $485 million. We assume a $90 WTI price, a $5 basis differential for LLS, and $2 off of WTI, or $88 as a realized price for our Eagle Ford oil production. To protect cash flows, we have 67% of our oil production hedged as a percentage of the midpoint of guidance for the rest of 2014, at a weighted average floor price of $92.94 per barrel.

For our program funding, using the midpoints of guidance, we expect our 2014 outspend will be around $265 million. $96 million of that has already been funded through the gas gathering system sale that closed in January. We expect the remaining $170 million to be substantially funded by the sale of our non-core assets, potential proceeds from our oil gathering system rights that is currently in market, and the final cash settlement from Magnum Hunter related to our Eagle Ford asset acquisition last year. That final cash settlement is in arbitration.

We expect a decision from the arbitrator by the end of the quarter. Magnum Hunter has indicated that we generally agree on a minimum of $26.5 million. We believe it's higher, but that will be decided in the arbitration.

Any remaining outspend would be funded on our credit facility. At quarter end, we had $100 million outstanding. Our current guidance provides for $315 million to $375 million drawn on the credit facility at year end. And as a reminder, this does not include any of the proceeds from asset sales, but it does include the Magnum Hunter final settlement that we agree on.

Under our current borrowing base of $475 million, we would expect to end the year with $100 million to $160 million of liquidity, absent any of these asset sales. However, we do have our Fall re-determination in October, where we expect to increase our borrowing base, as we have the last few times. If we receive a $50-million increase, which is the amount we received in the last two re-determinations, we would have year-end liquidity of $150 million to $210 million, even without any asset sales.

That concludes financial results and guidance review.

All right. Thanks, John and Steve. Kate, at this time, we're ready to take any questions.

(Operator Instructions)

Our first question comes from the line of Neal Dingmann from SunTrust. Please go ahead.

Good morning, guys. Great call. John, I guess -- Baird, for either, John -- just now, without, obviously, the success of this upper Eagle Ford, I'm just wondering how to attack at your thoughts, as far as a couple things there, as far as number one, the spacing you perceive? I know, John, you went into that a little bit.

And then secondly, how do you attack that from regions? Is it, you'll blanket each area, or more delineate that? I know you talked about this Martinson, the next one that you'll do. I'm wondering, going forward, how you attack that?

I'll take a stab at it first, Neal, and let John add anything if he wants to. I think at this point in time, we'll still continue to test the extensiveness of the upper Eagle Ford and the results by that testing.

As the year progresses, us having time to sit back and look at the Welhausen well, there could be a case to be made to swap out some lower Eagle Fords for some upper Eagle Ford. I see no reason at this time the spacing wouldn't be any different than what we've experienced in the lower Eagle Ford, anywhere from 400 to 500 feet or 50 to 60-acre spacing.

I would see no reason why we would adjust that spacing for the upper versus lower. But at this point in time, we're going to sit back and evaluate what we have done, look at production history, continue to gain confidence. At which time, again, our motive is to go ahead and drill the best wells we can with the best economics, and make some adjustments as time goes on. John, do you have anything else to say about that?

Just to add that the RBK unit that we had planned on drilling later in the year will test two lower and two upper in an offset staggered pattern, and we hope to gain some more information from that test.

Got it. Thanks, guys. And then just one follow-up. As far as, now with the additional locations, I know you mentioned, I think -- what was it -- the one spudder rig in addition to the other six. Will you add your thoughts about even adding another spudder rig? Does it make sense to do that? And then -- or just even more, maybe another one or two larger rigs?

So two questions there. Just overall rig count, your thoughts there, Baird, on how that might change, given the additional locations? And then secondly, does it make sense to go with additional spudder rigs? Is it cheaper to try that process versus having just additional larger rigs?

Again, I'll let John follow up. But I think the one spudder rig we have is okay with the six big rigs. As we continue to gain efficiencies on the drilling side, John mentioned in Lavaca County, of drilling all the intermediate holes, setting intermediate casing, and then walking back and drilling the production holes of that rig. That saves time.

So we think we can actually drill more wells with the current number of rigs we have. As far as accelerating activity, at this time, we have no plans to do so. But it's something we continue to look at. And especially with an increase in inventory because of the upper, it's something we will take into account more seriously, especially taking into account the sale of assets.

Very good. Thank you.

All right. Thank you.

Our next question comes from the line of Scott Hanold with RBC Capital Markets. Your line is open.

Good morning. So can you give a sense of what production is looking like right now? Obviously, there's a lot of wells that were, I guess, were back-end loaded. And certainly we need a pretty good surge of oil production coming through the rest of the year to hit the full-year targets. Can you give us a sense of where we're sitting at right now? Or the volumetric ramp through the year for oil?

For March, we averaged about 22,000 barrels a day equivalent net. I don't have a current figure, but with the recent turn-in of the Welhausen wells, with the recent turn-in of the White wells that John just mentioned, that we're making about 5,000 barrels a day equivalent gross on a net basis, we probably have 35% of that. So that's another 1,000 to 1,500 barrels a day.

I don't have a good figure right now, but I would expect, for the second quarter, we should be averaging around 24,000 barrels a day equivalent, if not more, because of the turn-ins, the accelerated turn-ins.

Okay, and the oil cut on average should really start to climb now, with these latest wells. It sounds like the pad that you're JV'ed with Marathon had some pretty high oil cuts. Is that going to continue with some additional drilling through the year?

We have a mix of wells. The -- we clearly got gassier with the Welhausen, but we should be able to maintain a mix between where we're drilling oilier wells and gassier wells, so as our historical mix ought to be about the same.

Okay, understood. And then one other question. You obviously talked about if you can have the Eagle Ford -- the upper and lower Eagle Fords coexisted, about another 400 potential locations. Bigger picture, when you look at areas where you have yet to really test the upper Eagle Ford and quite frankly, some -- I think some of the acreage where you haven't yet identified some of the even lower Eagle Ford. What could that 1,500 drilling location count move to over time?

Scott, if you add the other 400 locations we talked about, where both the upper and the lower coexist, you get to 1,900. We continue to pick up acreage, expect to get to that 100,000-acre bogey, or close to that 100,000-acre bogey by the end of the year. So that's another 15,000, 14,000 net acres.

You do the spacing on that, that probably adds another 150 to 200 locations with that additional lease-ac. So we should be able to -- assuming we feel confident about the upper and lower being separate, I would expect that 1,500 number to go to north of 2,000 toward the end of the year, beginning of next year.

And again, specifically, Baird, on the acreage that you all have right now -- and maybe I'm incorrect on this, but if you could correct me. But there is some areas I think to more the north where -- north and a little bit to the west, where you have yet to assign some upper Eagle Ford in some parts of the recent acreage acquisitions you've made to the east. I don't think you have really much identified for Eagle Ford at all. Is that a fair statement?

Yes, it is. As you go to the north and east, the lower becomes less prospective and the upper becomes prospective. We need to get out there and drill some test wells over time, as we continue to shore up our acreage position and increase the size of the drilling units. Whether we get that done all this year, or whether it slops over into 2015, is yet to be determined.

But the whole upper Eagle Ford, at least based on the results of the Welhausen and maybe the Martinson, and the Phage Tick, it just becomes a different play with a -- but is probably an extensive running room, yet to be defined exactly where that is. But it just makes this whole lease hold position big, and prospectively a lot bigger, based on what we know and what we're learning.

Okay. So that gets delineated over the next year, year and a half, okay.

I think so. The acreage that we have to the north, we continue to acquire acreage up there that's adjacent to what we have, just to make the units larger, so to give us more room to drill longer laterals. So that will be done throughout the remainder of this year, and probably not test at those-- that acreage probably until 2015, if I had to guess.

Understood. Thanks.

Thank you.

Our next question comes from the line of Subash Chandra with Jefferies. Your line is open.

Good morning. I was curious if you're seeing anything different in the rock lithology form from the upper and the lower? I understand your sample set isn't that big yet.

John, why don't you take a stab at that, please?

Sure. The lithology of the upper Eagle Ford, by definition, we're calling it a Marl, so it's about a 50% carbonate. So we do have that distinction versus the lower Eagle Ford has a much lower percentage of carbonate. So I would say that's the primary distinguishing lithologic distinction.

Yes. Do you think any of that feeds or influences into what you might see in the decline rate of the upper and lower? Or the IP of upper and lower? Trying to get a sense how much of this has just been enhanced perm in the upper, which shows up first and depletes quicker, or something of that nature?

Ultimately, we're putting away a lot more sand. You might have noticed we're able to pump a lot more sand in those upper Eagle Ford completions. So we're getting a -- what we believe is a very high stimulated rock volume, which would go beyond the primary perm and porosity that we encounter in the near well bore. So I think that it only helps you extend your fracture system beyond what you normally would by having the higher -- relatively higher perm and porosity that you encounter.

Okay, and you didn't lose anything in pressure. And I think you mentioned in the Martinson that the upper had higher pressure than the lower? And if you--

2,000, yes.

And what explanation? Was it seal in the upper and generating, and that sort of thing?

I would -- the easiest explanation that I can come up with is that it has not been influenced by the lower Eagle Ford well 400 feet away.

And is that 400 vertical displacement? Or was that (multiple speakers) --

Lateral.

What is the vertical displacement here?

On the order of 100 to 150 feet.

Okay.

And that's throughout the field. It may not be specific to the Martinson pad. But 100 to 150 feet is generally the vertical separation between the two.

Okay, and a final one for me. The -- probably going to pronounce it wrong -- [flot chug] -- what -- how did the GORs perform over time? Were they fairly stable, or rising, or falling?

On the five stick?

Yes.

Yes, I think it rose a little bit, but it was nothing markedly out of the ordinary. Most of these wells will have a little bit increase in their GOR over time, but there was nothing remarkable about it.

Congratulations, then. Thank you.

Thank you.

Our next question comes from the line of Steve Berman with Canaccord. Your line is open.

Good morning. Thanks. John, you may have mentioned this and I missed it. But in your previous slides, you've had a nice trend in quarterly well costs, both total and completion costs per frac stage. Do you have those numbers for the first quarter?

I think the number I quoted was roughly $9 million, or a little over that. And I think we had it down to -- was it 26 stages? So I think we are right around -- if I had to do the quick math, probably around $350,000 per frac stage.

Okay.

(multiple speakers) cost.

Okay. In terms of the two well housing wells total cost, did you notice any difference between the upper and lower Eagle Ford wells?

Well, both those wells cost more than our typical wells, as we upsized the well bores, we said 9 5/8 is our intermediate string. Our partner in the area at the time, GO7, which is now Devon, had encountered some drilling difficulties when we took the farm-out. So to overcome whatever drilling challenges that we might encounter, we upsized the well bore on the initial test. So I think going forward, we'll have a more typical well bore geometry.

But to get to the crux of your question, the difference between the two was not -- no real noticeable difference, other than we've learned a lot from drilling the first one, and it helped us drill the second one better. Primarily because we're in a new area that is -- we didn't have a whole lot of bit records at that depth and temperature.

And I know it's early in the game, but the 475 upper Eagle Ford locations you have in inventory now. Is there any way to break that down at this stage where you think, how much -- how many might be in this gassier area that the Welhausen well exhibited? Versus your historic oilier, lower Eagle Ford wells?

Yes, I think it's going to be on the trend that would be on strike with that running from the southwest to the northeast.

Got it.

So what he's saying, Steve, he's saying it ought to be about the same, probably, is what our expectations would be.

Okay. That's it for me. Thank you, guys.

Our next question comes from the line of Amir Arif with Stifel. Your line is open.

Thanks. Good morning, guys.

Good morning.

A few quick questions. On the [some are talking] Oklahoma assets that you have out there for sale, sounds like you got bids in. Is that something, if it happens, it will happen in the coming quarter? And can you remind us how much production is associated with that?

To answer the first question, if it's going to happen, it would happen this quarter. It may happen late this quarter, i.e. June, but it may move over into early July. But our expectation is going to be, whatever we get done, we'll get done this quarter.

As far as production, we're talking about 1.9 -- 1,900 barrels a day equivalent. Each one would be about that number.

And do you know what the gas cut is on that production?

In Mississippi, it's almost 100% gas. In Oklahoma, if you took about 35% to 40% of that would be well head and NGLs, with the remainder being dry gas.

Okay. Sounds good. And then on the acreage that you've been adding, it's been great the way you've been able to add it at $3,000 an acre. Is that acreage cost starting to move up, just with the upper Eagle Ford test well that are coming out, from you and from the rest of the industry?

I would expect it probably will start creeping up. It's hard to keep a good well secret. And I would imagine this will start getting some people's attention.

But as of today, the $3,000 to $3,500 an acre is a number that we keep -- we are successful with. But I can only imagine it may start to creep up.

And is most of this acreage [berg] that you're adding, is it just acreage that's expired from the previous owner, and you were able to lease it?

There are some top leases we put in, that we may put in place before it expires. But in most cases, this is brand-new acreage.

Okay. And then just final question on the Welhausen well. Can you provide some color on how the production is looking today, after that second May 7th cleanout?

I can tell you the test rates I saw this morning, we still got flowback crews out there. We filed W2s for both wells yesterday. Today's production is higher than yesterday.

So it's continuing to -- it's hanging in there, and at slight improvement, but we've held that choke where it's at. We may have one more choke size open on it, but we're going to be gentle with it. And try to understand and observe the longer-term production of this, before we get real aggressive with opening the choke.

But the GOR is holding in the same as your initial reported GOR?

Yes.

Okay, thanks.

Our next question comes from the line of Welles Fitzpatrick, Johnson Rice. Your line is open.

Good morning.

Hello, Welles.

Most of mine have been answered, but I'm having a little trouble on the HPDS, [bobbing] the RBK pack. Can you tell me where that's going to be?

Yes, that's going to be probably about right smack dab in the middle of our Shiner acreage.

Okay. So moving up-dip a little bit.

It will be a up-dip from the Welhausen, and probably on strike with our blonde, which was one of our [beer quide] wells. It will be just east of there, but in the center of our Shiner acreage.

Okay. Great. That's perfect. And then just one more one. And it's probably just statistical noise, but it looked like the 30-day rates from your Eagle Ford program were a little bit lower quarter over quarter. Am I right that that's probably just noise? Or did you guys move around to some different parts of the acreage?

There are some shallow wells in there that we drilled in our legacy acreage up in Cortez, the Millers and the Kusaks. Specifically, the Kusaks were two wells drilled in between -- on a down-space basis between two mature wells that had already produced 1,000 -- or 100,000 barrels. Likewise, the Millers were offsetting some mature producers. And as we go to a lot of these pad wells, we're often offsetting existing production. So I think the lesson learned is, the earlier you down-space, the better off you are.

And would that -- obviously, if you're going to move to dual development of the upper/lower, sooner is better, especially with that piece of info, but what -- how long -- and I know it's hard to pin down. But how long would you guys want to see the Phage Tick and the Welhausen and the Martinson, and even the RBK pads, before had you the confidence to move that into a development-type program?

I think we have the confidence to move those into the development program now. But with the six rigs that we've got in the drilling schedule, we've got -- there's just constraints on where we drill to meet our obligations elsewhere. But we've got the confidence in drilling those wells.

Okay, perfect. Thank you so much.

Thank you.

Our next question comes from the line of Adam Michael with Miller Tabak. Your line is open.

Good morning, guys.

Hello, Adam.

If I look at your recent slide presentation on the upper Eagle Ford, it looks like the fairway extends on into Fayette County, and there's a couple of sweet spots up there. And I was just wondering, are you guys leasing up in Fayette? And do you think it's prospective to the northeast?

We do think it is prospective up there, but I think a lot of that acreage is currently held by others. So we are focusing in the areas that are most accretive to our existing lease hold position, where we can block up existing acreage. We've got -- between Gonzales and Lavaca County, we think we've got ample room to grow that. And if the opportunity in Fayette County at some point comes, that's something to review at that time. But I think there's players up there in Fayette County that we would have to hop over and take additional geologic risk to get to any meaningful size of available acreage.

Okay. And I think the rest of my questions have been answered. Thank you.

All right, thank you.

Our next question comes from the line of Richard Tullis with Capital One. Your line is open.

Thanks. Good morning, everyone. John, going back to the question on the decrease in, say, 30-day rate, or even the rate per stage for the latest Eagle Ford wells versus, say, the prior group. Like wells to like wells, spaced -- evenly spaced apart, how do you look at the performance there? Versus, say, what you saw in the last two quarters, throwing out, say, some of the wells on the tighter spacing or on the legacy acreage?

There's a handful that we also had some mechanical issues on. We didn't get all the stages fracked, or we didn't get them all drilled out. We had a casing issue on one of them.

So there's a degree of variation that is going to -- is always going to occur. Hopefully, the mechanical issues we've addressed by changing our casing design, we've gone to a beefier casing with a better coupling, and basically changed out our tubular design to help overcome some of those issues.

And also, some of the longer laterals that we've seen, we haven't always been able to get them drilled out. So if you frac 32, but you can only open up 29, that creates an issue. Likewise, if you plan for 28, but due to a casing issue, you only get 23 away, that creates an issue.

So we've had a handful of those in this most recent set of wells, in addition to the shallower wells. And the mechanical issues are something that we hope we've got behind us. But it's something that we just continue to evolve the drilling and completion design to deal with the challenges they present.

And no change in your outlook on EUR estimates for Gonzales and Lavaca, correct?

No.

Okay.

Richard, just to add on to what John said, if you take this fairly small data set that John elaborated on, some of the mechanical issues we had, we don't view this as something we expect longer term. In fact, longer term, as we continue to say, we're drilling the best opportunities we can. And it took some time after we reported, like the Blonde and the Porter wells and the Bock wells, to get things ready to go ahead and exploit those specific areas with a more aggressive development program.

So you're going to see that development program progress further along in these better areas we've identified, based on IP and 30-day rate. So it's just a quarter data set that has some noise in it, I guess, probably the best way to say it.

Okay. Thank you. That's helpful. And looking -- I know it's early -- certainly early for this Welhausen well. If I remember correctly, did a third-party engineer give you 450,000 barrels for that first upper Eagle Ford well?

It's drifted around. I think originally it was 350,000. Then it went over 400,000. I thought it was 420,000 or --

Okay.

And now, at year end, it's back down to 390,000. It's not unusual for these things to drift around here for early in their history, until the eternal decline rate is clearly identified. So it's somewhere -- at the end of the day, I think it's going to be somewhere around 400,000. It could be north of that, because I think in terms of client rate our third-party engineer is using is too steep.

We're using a 12% terminal decline rate on this stuff, which, at least based on my years of experience on resource plays, I think that's way too aggressive. But that's what these guys are doing, and I -- they do the reserve. So -- and if you change that 12% to 6%, for instance, I can't tell you exactly how many reserves you add, but it's material. You don't add a lot of present value, but you add a lot of reserves.

Sure, sure. And then just lastly, in general, where's the Eagle Ford acreage that you've acquired over the past couple of months? I guess it was the 6,400 acres?

John?

It's in the area of the Welhausen, and on strike with that to the northeast.

Okay. That's all for me. Thank you.

Our next question comes from the line of Ravi Kamath with (inaudible). Your line is open.

Hello guys. Couple of housekeeping questions. One on your revolver. I know your borrowing base went up to 475. Did lender commitments also go up to that level, or is it still at 400?

We took lender commitments up to 450.

To 450, okay, great. Great. And just secondly, operationally, with regards to the -- I know you have been leasing in some areas. Just wanted some thoughts on the Hunt acreage in that JV? And are you actually letting any acreage go at this point?

No, we're not letting any acreage go at this point. All that acreage has been HBP-ed. The 6,500 acres -- net acres that Hunt operates, they have HBP-ed all that acreage, and changed their drilling in the fourth quarter of last year to other parts of their Eagle Ford play. So we don't anticipate any acreage in that area expiring due to lack of activity.

Got it. And then one last one. Just looking at some of the wells that you guys reported on this time around, I would point out the Leal 4H and I think the Pavlicek 5H and Berger-Simper 1H, all of them look like the 30-day IPs came in at less than 50% of the 24-hour IP. And was just wondering if there were any specific issues related to those wells? And anything you could -- any color you could provide on that would be helpful. Thank you.

Okay. On the Leal, one thing I will mention is, those two wells were our tightest spacing test. Those wells were drilled at 375 feet apart. And on the Leal number 4, we had a casing issue, and we did not get 5 of our 28 planned stages fracked. So we did not get all of that put away as we would like to.

On the Pavliceks as well, those were down-spaced infill wells, and one of them only had a -- 20 frac stages. So once again, I would say the lesson learned here for us is, down-space, earlier is better.

Got it. And you are still thinking the 40-acre down-spacing? How many of those tests have you gotten done? And is that still the expectation, that 40-acre is going to work?

Yes, I think it's going to be in the 40- to 50-acre, depending on the actual lateral length. That's still our current plan of development.

Thanks, guys.

Thank you.

Our next question comes from the line of Gail Nicholson with KLR Group. Your line is open.

Good morning, gentlemen.

Hi, Gail.

Just a quick -- curiosity regarding optimal lateral length. You guys have done a mixture of shorter and longer laterals. And I was just curious if you guys have an idea of what you think is going to be the best lateral length, going forward? Or if you're still in the testing phase?

Right now, we are constraining, for the most part, our laterals to a complete-able lateral length at 7,500 feet. There will be occasionally one that will exceed that, mainly because of a unit configuration, geologic issue, or something that would prevent you from getting it with another well bore that will reach out and drill a little bit deeper. But for the most part, I think going forward, our plan is to constrain our lateral length to around 7,500 feet of treatable lateral.

Okay, great. And then just looking at the -- in Lavaca County, the acreage, the Far East acreage. When -- do you guys have any plans to test that -- the furthest eastern expansion of the Lavaca in 2014? Or is that a 2015 and beyond story?

I think that's going to be a 2015 and beyond story. We've got a bit of acreage that we've added in northern and eastern Lavaca; some of it is nice and blocky. The rest of it, we are trying to grow those into larger drilling units.

We don't want to just have one 200-acre drilling units out there. We strive to build 600, 700-acre drilling units. So I would say that would be something beyond this year's drilling schedule, as we've got this year's drilling schedule fairly firmed up.

Great. Thank you very much.

Thank you.

Our next question comes from the line of Kim Pacanovsky with Imperial Capital. Your line is open.

Good morning, everyone. Baird, you said that by the end of the year, you could be up to about 2,000 locations, which is obviously a huge number. And it's not unreasonable to expect a step change in CapEx to -- you're a victim of your own success with that location count. So can you just talk about some of the options to fund a significantly larger program, as you see it now?

First of which is the sale of assets that Steve elaborated on. We'll take a wait-and-see attitude and see how we do there. We could always bring a partner in. Parts of the acreage that may be conducive to bringing a partner in, if we want to ratchet up activity. And lastly, capital markets are always an option. We just have to wait a day to accelerating the drilling activity to the value of going to the capital markets, both debt and equity.

So it's just all of those options are on the table at this time. Yet to be determined exactly what we may do. But clearly, with this many things to do, and a 15-plus year inventory, it would make sense for us to figure out a good way to accelerate drilling activity.

Yes, great. And on that RBK pad, what exactly is the timing of that pad? I'm wondering whether you're going to -- how many months of production you'll have before your 2015 CapEx is finalized?

RBK, we should start drilling on that in the third quarter. And we would probably have first sales late this year, early next year.

Okay, great. Everything else has been answered, so congratulations on the upper Eagle Ford.

Thanks, Kim.

Our final question comes from the line of Warren Darilek with Southwest Securities. Your line is open.

Good morning, gentlemen. Good call. On the upper Eagle Ford everyone's talking about, can I geographically take a picture of this? There's a line from Welhausen to Martinson to what will be RBK to [five stick]. Is that line a general rough estimate of this new 475 wells mentioned? Is it like a rectangle, with that being the center point, some east, some west of that line? Or how do you describe that, this new upper area?

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

Okay. I would say, if you could imagine a teardrop with the point up, and that would be up around where the five stick is. And then it would -- the upper end of that teardrop would go along the line that you mentioned, maybe a little bit northwest of it, and then roll down to encompass the rest of our lease hold to the south and east.

Okay, down to the Welhausen?

Past the Welhausen, yes.

Past Wel -- Okay, great. Okay. Appreciate it. Great quarter.

All right. Thank you very much.

At this time, I would like to turn the call back to Management for closing remarks.

All right. Thanks, Kate. I hope you can see we're making progress. I realize we have some noise in the first quarter. But at this point in time, we strictly consider it noise, and we have no reason to expect that we can't continue to grow this thing, grow the Eagle Ford. Continue to take advantage of what we think we have a huge opportunity in the upper at this point in time. And really, as the year progresses, look forward to continue to bring you up to date. With that, good day.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone have a good day.