Ranger Oil Corp (ROCC) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation fourth-quarter 2013 earnings call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will be given at that time.

(Operator Instructions)

As a reminder, this conference call is been recorded. I would now like to turn the call over to Mr. Baird Whitehead, President and CEO. Please go ahead.

Destiny, thank you. I'd like to welcome you to Penn Virginia's fourth-quarter 2013 conference call. I am 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 the language in our forward-looking statement sections of the press releases issued yesterday, as well as our Form 10-K which will be filed on Monday, February 24.

In the fourth quarter, operating cash flows and margins remained strong, and as reflected in the table in our operations update, we drilled some very, very good Wells with the highest IPs and 30-day rates of any Wells since inception of our activity in the Eagle Ford. Some of the highlights through the fourth quarter and year-end include -- proved reserves right now over 136 million barrels, or about 20% higher than last year of course due to our ongoing growth in the Eagle Ford. Partially offset by some downward revisions to our gas spuds in Mississippi and East Texas as a result of the SEC five-year rule.

The year-end proved reserves of 136 million were 45% oil and 16% NGLs, 40% developed with the PV10 of about $1.7 billion. Year-end 2012, our proved oil percent was 22%. NGLs were 18%, and the PV-10 of our proved reserves were $692 million.

So, in 2013, we had an increase in proved PV-10 of almost 150% while our oil reserves increased from approximately 25 million barrels to 61 million barrels equivalent, or an increase of 144%. As of year-end 2013, the proved reserves of the Eagle Ford were 76 million barrels, or 55% now of our total proved reserves and were 89% oil and NGLs with a PV-10 of almost $1.6 billion.

Fourth quarter oil production of 11,130 barrels of oil a day was 7% higher than the third quarter, and although consistent with our previous guidance, it would have been higher had there not been some delays in completion internalized in the fourth quarter that were pushed into early into the first quarter of 2014. Fourth quarter product revenues were $117 million, or approximately $64 per barrel oil equivalent, which is a 4% decrease from the third quarter due to 10% lower oil prices partially offset by the 7% increase in oil production. Oil and natural gas liquid revenues represented about 90% of our total product revenues with oil by itself representing 83% of our fourth-quarter product revenues.

Operating margin of $47 per barrel oil equivalent decreased 7% from $51 in the third quarter, again due primarily to the lower oil price as well as some nonrecurring G&A items that Steve will discuss in more detail here soon. Operating income was approximately $15.5 million, which compares to $24 million in the third quarter, excluding a third-quarter $132 million impairment expense.

Adjusted EBITDAX was approximately $84 million, or a 4% decrease from the third quarter. And lastly, adjusted net loss was $6.7 million, or $0.10 per diluted share compared to the adjusted net loss to $1.5 million in the third quarter, or $0.02 per diluted share.

We made a significant amount of operational progress in the fourth quarter as reflected in the results of the Wells completed in the fourth quarter and into 2014. Oil prices and cash flows were somewhat lower compared to the third quarter, but going into 2014 with a significant drilling and completion activity, excellent results for the Wells we're drilling, and therefore growth of oil production -- cash flow growth is expected to resume.

Steve will touch later upon the specifics of our 2014 guidance, but the primary driver of increased production and cash flows in 2014 is in the Eagle Ford drilling program that is focused on down space Wells, multi-well pad drilling, and zipper fracs in areas that we anticipate excellent results based to a large extent on what we have learned from the results of the 2013 program and those specifically drilled in the third and fourth quarter of last year.

We have actually adjusted our drilling program from what was assumed at the time of our preliminary 2014 guidance. You can certainly see in the table in the operations update that we have drilled some excellent Wells in the fourth quarter and early this year. We have what we think is a very high-quality drilling program in 2014, and therefore it is expected that 2014 oil production will grow between 66% and 78% year-over-year.

Also, in our press release, we reported that we are now up to 80,000 net acres in this play. We have added about 13,000 net acres since early August at a cost of about $2,800 an acre.

Since our Eagle Ford acquisition last April, we have been successful in building our acreage position from approximately 53,000 net acres post-acquisition to about the 80,000 net acres now. Our near-term goal remains at a minimum 100,000 net acres, and we feel at this time we should be close to this goal by the end of the year with the capital dollars allocated in the budget to leasing acquisitions.

With our ongoing leasing effort and the encouraging results of our down space drilling program, which John will elaborate upon, we now estimate that we have the remaining drilling inventory of about 1,125 locations, a 26% increase from the 890 locations we communicated in early November. Including lateral's drilled, our effective spacing has decreased from about 106 acres per location to about 90 acres per location reflective of our excellent results to date from down-spacing as well as our ongoing progress in adding bolt-on acreage and forming new joint ventures.

We continue to add significant value to the Company with attractive lease acquisition costs that a snapshot in time now represents a drilling inventory of over 10 years based on our current activity level. We only expect add to this inventory with further acreage additions, ongoing success in down-spacing, and potential success in the upper Eagle Ford.

Speaking of the upper Eagle Ford, in the press release, we discussed the status of our most current tests referred to as the Welhausen pad. We just ramped production casing on this upper Eagle Ford test well. The lower Eagle Ford offset was drilled and cased in January, and as discussed in the past, our goal now is competing both of these Wells to test the upper and lower and to see if they in fact are separate reservoirs.

Completion should begin shortly on both of these Wells with IPs expected probably later on in March. In addition, we have spud a subsequent upper Eagle Ford well approximately two miles to the north referred to as the Martinson well. There is an existing lower Eagle Ford producing well in this existing unit, which we are offsetting, so again, our goal is to determine if the upper and lower Eagle Ford are separate reservoirs.

I would hope with our ongoing test that we have this question answered by the middle of this year. In addition, this will help us to determine the potential of the upper Eagle Ford as a standalone reservoir and help direct our leasing activity where in fact only upper Eagle Ford potential may exist.

And lastly, our short-term goal of improving liquidity is on track. We recently closed on the sale of our Eagle Ford gathering and [gas link] assets and received about $94 million net to our working interest. As a result of this sale, our pro forma financial liquidity as of December 31 was approximately $340 million.

In addition, as announced, we have retained a financial advisor to assist in the sale of our mid-continent granite wash and Mississippi Selma Chalk assets. The data room is open. CAs are being signed, and we expect to complete these asset sales during the second quarter of this year.

The proceeds of all of these asset sales will only help improve our liquidity further of course and allow us to accelerate production and cash flow growth and at the same time help fund our 2014 [I] spend. Steve will get into some more detail concerning liquidity here in a minute.

So, with that, I would like to go ahead and turn this call over to Steve.

Okay. Thanks, Baird. Good morning.

I'll start with the comparison of our fourth-quarter financial results to the third-quarter results. Product revenues for the quarter were $117.1 million, or $63.58 per barrel of oil equivalent, down 4% from the third quarter. The decrease was primarily commodity price-driven.

As Baird mentioned, our oil production was up for the fourth quarter, but our realized price for crude oil declined 10% from $105.37 to $94.66 per barrel. 83% of our product revenues are derived from oil sales so that's a significant decrease in pricing, and also recall our hedges are not included in product revenues.

Operating expenses were $30.4 million for the quarter, or $16.51 per barrel of oil equivalent, which was $600,000 higher than in the third quarter. Lease operating expense increased in the fourth quarter primarily due to higher than usual repair and maintenance activity in East Texas and the Eagle Ford. This was offset by continued improvements in compression expenses as we rationalized our compression use especially in East Texas.

Gathering, processing, and transportation expense was slightly higher due to higher Eagle Ford volumes. G&A expense, excluding non-cash, share-based, and liability-based incentive compensation was [$10.] million for the quarter, or $5.94 per barrel of oil equivalent. Up $300,000 from the third quarter.

There were $1.1 million of one-time costs related to recent accounting system implementation and acquisition audit fees. Excluding these nonrecurring costs, our recurring G&A expense would have been $9.8 million for the quarter.

Our liability-based expense, which is related to our performance-based restricted stock units was $2.6 million for the quarter. This is higher than past quarters because of the strong stock performance during the quarter. This expense is currently non-cash but could be paid out in cash if earned when the units start vesting in 2015.

Company-wide operating margin as described in our earnings release was $47.07 per barrel of oil equivalent. The non-cash and nonrecurring G&A items I just described decreased this margin by about $2 per barrel of oil equivalent, which when normalized out, brings our recurring cash margin more in line with past quarters.

Cash margins in the Eagle Ford continue to be strong. Even with a lower realized oil price, our operating margin for Eagle Ford production in the fourth quarter was about $72 per barrel of oil equivalent excluding allocated G&A.

Adjusted EBITDAX a non-GAAP measure reconciled on page nine of the release was $84.4 million for the quarter compared to $88.3 million in the third quarter. The lower adjusted EBITDAX was primarily due to lower realized commodity prices, higher one-time G&A costs, and higher repair and maintenance costs offset by higher production especially record high oil production.

For our non-cash expenses, DD&A expense increased to $36.50 per BOE, up from $34.56 per BOE. This was primarily due to negative proved natural gas reserve revisions, which resulted in higher DD&A rates, especially in East Texas. Exploration expense decreased to $2.9 million primarily due to lower unproved property amortization.

Our adjusted net loss attributable to common shareholders, which includes the preferred stock dividend of $1.7 million -- $6.7 million for the year and other adjustments reconciled on page nine of the release was $6.7 million, or $0.10 per share. This compares to $0.02 per share loss in the third quarter.

Capital expenditures for the quarter were $150 million, an increase of $30 million from the third quarter. The increase was primarily due to leasehold acquisition were we spent $40 million in the fourth quarter compared to $5 million in the third quarter.

For drilling and completion activity, we spent $104 million compared to $112 million in the third quarter. Drilling and completion spending was significantly below our guidance range due to some delayed completions originally planned late in the fourth quarter as Baird mentioned.

If we had completed and turned in line all Wells that were planned in the fourth quarter, we would have spent about $30 million of additional drilling and completion capital. That $30 million is now included in our 2014 guidance as carryover.

Moving on to capital resources and liquidity, at year-end, we had $206 million outstanding on our credit facility and $24 million of cash on the balance sheet. Our borrowing base at year-end was $425 million, giving us financial liquidity of $240 million net of letters of credit.

In February, we closed on the Eagle Ford gas gathering sale to American Midstream for gross proceeds of $100 million. Including purchase price adjustments and payoffs to working interest partners, we had net cash proceeds of $98.4 million. The pro forma for the asset sale proceeds, our year-end liquidity was nearly $340 million.

Our leverage at year-end was 3.7 times total debt-to-pro forma-adjusted EBITDAX compared to our credit facility covenant of 4.5 times. Pro forma adjusted EBITDAX, which includes a $26 million pro forma cash flow adjustment related to our Eagle Ford acquisition as permitted in our credit facility, is $342.4 million for the trailing 12-month period. Pro forma for the asset sales proceeds, our year-end leverage was 3.5 times.

Moving on to hedges, we have been very active in adding swaps and collars to our oil portfolio for 2014 and 2015. We currently have 10,000 barrels a day of oil hedged for 2014, which is 62% of the midpoint of guidance at a weighted average floor price of $93.55 per barrel. We have 6,000 barrels per day hedged for the first half of 2015 and 5,000 barrels per day for the second half of 2015.

The weighted average floor price for the full year of 2015 is $89.10. Our current hedge position is summarized on page 11 of the release.

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 the Selma chalk and granite wash assets that are currently on market. If and when we sell those assets, we will update guidance accordingly.

We are planning to run a six-rig operated program with all drilling taking place in the Eagle Ford. We plan to drill approximately 98 gross and 53 net Wells and will turn in-line a similar number of Wells through the year. We will tentatively run three rigs in Gonzales County and three rigs in the Lavaca County, and there is a table on page 5 of the release that details that planned activity.

Our capital program for 2014 is expected to be $575 million to $640 million. This is $65 million to $100 million higher than our previous guidance. A primary driver for the increase is leasehold acquisitions. Our leasehold guidance is now $40 million to $70 million up from a preliminary guidance of about $25 million.

As Baird mentioned, we have been very active in adding leasehold around our core position. To date, we have spent about $6 million and expect to keep adding land at about $2,500 to $3,000 per acre as we get closer to our goal of 100,000 net acres.

For drilling and completion, we expect to spend $510 million to $540 million which is up about $40 million to $45 million over our previous guidance. This extra spending is coming primarily from $30 million of carryover from the 2013 program and from adding 2.5 net Wells to the drilling program. If you adjust for carryover and our well contingency costs -- it's in the release at $15 million. That equates to an average well cost across the whole program of approximately $8.8 million for 2014.

Production is expected to be 9.1 million to 9.8 million barrels equivalent, which equates to 25,000 to 26,800 barrel of oil equivalent per day. Oil production is expected to be 5.7 million to 6.1 million barrels of oil, an increase of 66% to 78% over 2013 oil production.

Although overall Company production is in line with prior guidance, our oil production guidance is somewhat lower. The primary drivers of the decrease come from rescheduling the drilling program to emphasize development near recent excellent well results in the Shiner area with higher GORs, some turn in-line delays early in 2014, adjustments to the early time performance of the type curve associated with down-spacing, increasing the offset well shut-in assumption related to zipper fracking, increasing the number of days for flow-back and cleanup of multi-well pads, since now we are drilling as much as four Wells per pad. This overall decrease is offset by better well results expected from increasing the number of frac stages and in putting away more profit per stage.

As we have been mentioning over the last several quarters since we started drilling multi-well pads, our production volume is going to be lumpy and difficult to predict on a quarter-by-quarter basis. But, as we currently have it modeled, we show strongest growth in 2014 in the second quarter with moderate growth in the first and third quarters. We expect our exit rate for oil growth, which we are defining as fourth-quarter 2014 oil production over fourth-quarter 2013 oil production to be about 55% to 65% and total production growth at 30% to 40%.

Production revenue is expected to be $587 million to $630 million which is a 36% to 46% increase over 2013. This is based on our commodity price assumption of $90 for WTI, $5 for an LLS basis differential, $7 off of that for transportation, which nets WTI less $2 for our realized oil price in the Eagle Ford, $4 for natural gas, and $29 for NGLs. Revenue does not include cash settlements from hedging. With these price assumptions I just mentioned, we would expect our hedges to contribute about $11 million to cash flow.

We expect our lease operating expense will be higher on a per-unit basis due to a higher contribution of oil production and higher compression charges related to the Eagle Ford gas gathering system sale. For gathering, processing, and transportation, we expect to be about $5 million higher in overall spending, but that's flat on a per-unit basis despite the higher gathering fees due to that gas gathering system sale. We expect the sale of our gas gathering system added about $8 million of incremental expense to 2014 which is included in the guidance.

Recurring G&A is still expected to be around $11 million per quarter. Unproved property amortization, which is the primary component of exploration expense, is significantly lower in 2014 compared to 2013. This is due to more unproved property being reclassified as proved at year-end and lengthening of the amortization schedule.

DD&A is remaining relatively constant at about $35 to $36 per barrel. Adjusted EBITDAX, which includes cash settlements from hedges, is expected to be $440 million to $485 million, assuming the commodity pricing I already discussed. And, this would be a 39% to 53% increase over 2013.

For our program funding, using the midpoints of guidance, we expect our 2014 outspend would be around $250 million. $98.4 million of that has already been funded through the gas gathering system sale. We expect the remaining approximately $150 million to be substantially funded by our sale of Selma Chalk and granite wash assets. Any remaining outspend would be funded on the credit facility.

At year-end, we had $206 million outstanding on the $425 million borrowing base, and at year-end 2014, we would expect to have about $225 million to $250 million outstanding on the credit facility. We expect our borrowing base will increase about $100 million in 2014 through drilling in the Eagle Ford.

If the asset sales are complete though, we would expect a reduction in our borrowing base of about $100 million. So, in this scenario, our borrowing base at year-end 2014 would remain at about $425 million, and our liquidity would be $175 million to $200 million.

We also expect to receive a final settlement from Magnum Hunter related to our Eagle Ford acquisition of at least $26 million. That final settled amount is still being finalized, and given we have received this money in 2014, our liquidity would be at least $200 million at year-end. Also, at year-end, our leverage would be up about 2.9 to 3 times debt-to-adjusted EBITDAX.

Now, looking into 2015, we are currently planning for a similar capital program to 2014 with not as much spending on lease acquisition. We are considering a $550 million to $575 million program with about 105 to 110 gross Wells and 55 to 60 net Wells. That program would produce about 30% oil production growth over 2014 -- 20% total production growth and 20% growth in adjusted EBITDAX and cash flow per share.

We expect our leverage would continue to improve to end the year at about 2.7 to 2.8 times debt-to-adjusted EBITDAX. We would fund the outspend with the credit facility and would likely term out debt to maintain our liquidity at least $150 million.

That concludes the financial and guidance review, and with that, I'll turn it over to John to discuss our operational progress.

Thank you, Steve, and good morning.

As Baird mentioned, in the fourth quarter, our reserve production and acreage basis increased, and we continue to have success in the Eagle Ford shale. Touching upon some of the recent operational highlights -- our fourth-quarter production was 20,000 BOE per day, up 2% from the third quarter. In the fourth quarter, Eagle Ford shale production accounted for 13,100 BOE per day, which is a 5% sequential increase over 12,500 BOE per day in the third quarter.

We had another record quarterly oil production of 11,100 barrels of oil per day, a 7% sequential increase. Oil and NGL volumes were 68% of total volumes in the fourth quarter compared to 67% from the prior quarter.

Oil production was 56% of production during the fourth quarter compared to 53% in the third quarter. Despite this growth and being consistent with our guidance for the fourth quarter, our production was less than it could have been during the fourth quarter due primarily to the timing of turning in-line a number of Wells which occurred later in December or January as Baird and Steve mentioned.

Currently, we have 179 Eagle Ford shale-producing Wells. We have 13 operated Wells completing or waiting on completion, 2 outside operated Wells waiting on completion, and 6 operated Wells being drilled. No non-operated Wells are currently being drilled.

Our average IP for the 23 most recent operated Wells was 1,582 BOE per day with an initial 30-day average gross production rate for 19 of those 23 Wells with sufficient 30-day history was 1,076 BOE per day. These average results are markedly better than our previous report.

The average lateral length for these 23 Wells was approximately 5,700 feet [perf to perf] with an average of 24.3 frac stages. These average dimensions are slightly less than our previous report.

In general, the better results can be attributed to pumping higher concentrations of profit per stage during zipper frac operations on multi-well pads, concurrent with achieving a lower well cost per stage. Clearly, we are beginning to see the advantages associated with pad drilling and closer well spacing which improves induced frac efficiencies, and therefore, overall production rates.

22 of these 23 recently drilled Wells were drilled off of 10 multi-well pads, or just about a little over two Wells per pad on average. Effective nominal spacing on these nine pads averaged 60 acres. The closer spacing, the use of zipper fracs, and higher profit concentration per frac stage appears to be working extremely well.

With respect to profit in the fourth quarter, we pumped an average of 7.9 million pounds of profit per well. This averages about 325,000 pounds per frac stage compared to an average of about 280,000 pounds per stage in the third quarter, which is an increase of 16%. It results in average of between 1,300 and 1,400 pounds of profit per foot of lateral.

In the fourth quarter, we completed 19 Wells with average total well cost of approximately $9.15 million with an average of 24.1 frac stages. This compares to 16 completed Wells in the third quarter with an average total well cost of approximately $8.53 million with an average of 21.9 frac stages.

We can break that down further. We spent about $380,000 of total well cost per frac stage in the fourth quarter as compared to $390,000 of total well costs per frac stage in the third quarter, and that compares to roughly $440,000 during the second quarter. In terms of purely stimulation costs, however, on a per-stage basis, our current prices are below $120,000 per stage with about 300,000 pounds per stage.

Moreover, during the fourth quarter, the average peak gross production rate per frac stage was 67 BOE per day, and the 30-day average gross production rate per frac stage was 45 BOE per day -- increases of 18% and 19% over our averages of 57 BOE per day and 38 BOE per day in the third quarter. These improvements are not only attributable to contractual changes, which are substantial, but also due to the continued evolution of our stimulation design.

Our most current completion design consists of 225-foot stage spacing with 5 perforation clusters per stage and pumping about 300,000 pounds of profit, maintaining the 1,300 to 1,400 pounds of profit per foot of lateral. We think this covers an additional 10% to 15% more of the lateral pay section, increasing overall stimulated rock volume, or SRV, and higher productivity appears to support it.

This evolution includes going to a hybrid frac design, which minimizes gel requirements as well as reduced potential formation damage, increasing our sand concentrations up to 4 pounds per gallon when the formation will take it. And, on a quicker ramp, further reduces water, chemical, and pump times, all the while placing more sand in the formation and maximizing SRV.

We are using 100 mesh on the front end to improve overall fracture complexity followed by white sand, and then we tail-end with a resin-coated profit. This not only reduces costs but also reduces or even completely eliminates profit flow-back while providing the advantage of a profit packed with a higher rated closure stress.

Our stimulation design continues to evolve as we more tightly engineer our fluids and pumping schedule to further increase the amount of profit pumped per stage or per foot of lateral while keeping our incremental costs low. And, again, when we do all of that on multi-well pad, the completion efficiency is just multiplied.

On the drilling side, we are also achieving some additional efficiency gains from the pad drilling. Whenever possible, we utilize walking rigs to further reduce rig release to spud cycle time and the use of smaller spudder rigs to preset surface casing on multi-well pads. When we are able to combine the preset surface casing with the walking rigs, that can save us up to $70,000 per well and over 50 hours of cycle time with the big rig.

Even without a full year's benefit of using the spudder rigs with the walking rigs, our drilling team continues to reduce our drilling cycle time and costs. Not to mention that we are drilling deeper Wells with longer lateral's. Compared to 2012, our drilling cost per foot in 2013 was reduced by 18% in Gonzales County and 24% and Lavaca County.

Using the multi-well drilling pad is also complemented by use of rotary steerable directional tools, which tend to deliver a smoother well bore and increased rate of penetration further saving about $200,000 per well. So, all of that adds up to four consecutive quarters of declining per-stage total well costs even though we're drilling longer lateral's, completing more frac stages and achieving more productivity per stage.

With regards to down-spacing, we have an encouraging data point to report. We just IP'd two Wells, the Cusack Number Two and the Cusack Number Three for 982 BOE per day and 830 BOE per day, respectively, for a pad total of 1,812 BOE per day. Their W-2 filings should show up any day now.

These two Wells were drilled in the shallower, lower GOR portion of our Cortez acreage in Gonzales County. While this portion of our acreage has produced a lot of oil over the last three years, typically the per well productivities in this part of our acreage are not at the high end of range of rates shown in our recent IP table. Primarily because, like I said, of the lower reservoir energy associated with lower GORs and relatively shallow PVD.

These two Wells' lateral's were drilled 400 to 500 feet apart but also importantly were located in between two existing Eagle Ford shale Wells. The two older parent Wells had been drilled about 1,500 feet apart. Each of the two older outside Wells have already produced 100,000 barrels of oil equivalent or more in about a year.

The combined IP of the two original parent Wells was 1,896 BOE per day. The combined IPs of the two, new down-spaced in-fill Wells drilled a year later is 1,812 BOE per day.

So, while it is still early, we view this as an encouraging data point in the down-spacing aspect of our plan of development. Namely, that we drilled two successful in-fill Wells between two material producers, and we're seeing similar rates -- 1,812 BOE versus 1,896 BOE per day at similar wellhead pressures. We need to evaluate this over a longer period of time, but the initial report is certainly encouraging.

Back to our 2014 program, we plan to spud 98 gross and 52.5 net wells and expect to turn in the lines 97 gross and 53.2 net Wells. As a result, in the fourth quarter of 2014, total Company production is expected to be approximately 30% to 40% over the fourth quarter of 2013 with oil production alone growing 55% to 65%.

With respect to well economics for planning purposes, we estimate that at $90 per barrel WTI pricing, we will create gross average PV-10 value per well of about $6 million to $8 million for each typical well in the Peach Creek and Shiner fields. Assuming costs of between $8.1 million to $9.6 million with an average pretax rate of return of 50% to 60%. Having said that, we believe our most recent Wells may see these excellent economics, but we will need more time to confirm that.

Lastly, as Baird mentioned, we remain enthusiastic with the potential of the upper Eagle Ford shale interval. We've just ran production casing on an upper Eagle Ford test well, our Welhausen A2H, along with the adjacent lower Eagle shale well, Welhausen B1H, should be completed some time in March.

Furthermore, we are currently drilling the lateral on our third upper Eagle Ford shale test well on the Martinson pad. Our first upper Eagle Ford shale test well, the five stick, had accumulated roughly 85,000 BOE during its first 292 days, and we think that is a good performance, giving a short lateral of 4,200 feet and only 17 frac stages and fairly light frac intensity of only 240,000 pounds per stage of profit. By comparison, our upcoming Welhausen A2H will -- tentatively will have 27 stages and a lateral length of 6,000 feet.

Assuming these tests work in terms of producing both economically as well as separately from the lower Eagle Ford shale, we could shift our development plans to accommodate both upper and lower Eagle Ford shale drilling and completions during 2014 and beyond. Clearly, in this situation, the potential additions to our drilling inventory in value could be significant.

So, with that, I will turn it back to you, Baird.

Okay. Thank you, John. Destiny, we are ready to go ahead and take any questions please.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning, guys. Great news, Baird. Baird, a question, obviously, your outcome on these last 23 wells, your IP as well as the 30-day rate continues to improve dramatically. I'm just wondering going forward, are we going to start to see that level off a bit? Is this just because of the drilling and completion techniques and longer spacing and all of that, that were used? Or how much more improvement can we continue to see?

Neal, that's a difficult question to answer, of course. I think that everything we've mentioned, as far as spacing and zipper fracs and some of the refinements that John mentioned, has clearly added to the potential or to the increased IPs.

As far as whether we can continue to do that, I think we'll probably start -- we'll continue to see some subtle increases but I would - as we continue to do things maybe differently, maybe we start putting some more sand away. We'll probably take this in incremental small steps. But if we can stay focused in the areas in which we have drilled some excellent wells and see close to these 2,000 barrels of oil per day rates alone, plus the NGLs and gas, we'd be extremely happy. And we've not really baked that into our production forecast for the year.

We have been somewhat -- we tempered our enthusiasm until we get some more results behind us. But there clearly is some upside in what we would expect the production to be through the year if we continue to drill wells that were in the same ballpark as the Blonde, Hunter, or Porter or some of these other wells we had shown in the ops update.

Okay and then one follow-up, if I could, bearing on the Upper Eagle Ford, I know -- I think this third one, talking to Jim, sounds like it's going to be a bit longer lateral, a few more stages. Your thought, I guess on if you'd share how much more improvement we might see on this one versus maybe the first one that it was reported? And then secondly, any thoughts on just how much of your acreage is perspective for the Upper Eagle Ford?

Well, the only thing I can tell you at this time that gives us some encouragement on the well house in the Upper Eagle Ford is we carried a lot of gas as we drilled that lateral. I can't -- it's not necessarily a direct correlation of mud lock shows versus performance. But you clearly would rather have good mud lock shows than not and I -- it's hard to answer. We've got to get some more of these under our belt, as far as what our expectations are.

One thing I can say, the Fojtik, which was our original well. As some of you remember, I think originally we had said that we thought ultimate reserves on that well was about 380,000 barrels. As -- at year end, because of how this thing had actually (inaudible -- technical difficulties) some quasi-leveled out, we actually booked 450,000 on it and that's an [outside] reservoir engineer number.

So it does give us some comfort that the Fojtik will, even though it may have underperformed early on, clearly, as time went on, as the year went on, its decline rate adjusted down somewhat. So in any case, I don't know if I answered your question. I'm sort of not answering it directly, because I don't know the answer at this time.

But again, we have got to get this well house and pad completed; we've got to get the Martinson well completed. Actually, the Martinson #1 well, the existing well, the Lower Eagle Ford and that pad, if I'm not mistaken, is over 700,000 barrel ultimate well, so it's in a good area.

So we're pretty enthusiastic about what we're doing on the lower end and the upper, and if we can have some positive indicators early on this Upper Eagle Ford, we consider it a home run and without a lot of finish to do and give us some flexibility on moving locations around or moving our joint program around if it is deemed that it makes a lot of sense to do that. So it certainly opens up a lot of opportunities for us.

Brian Corales, Howard Weil.

Hi, guys. One question on the inventory. It was a nice increase. Can you tell us what you booked? How many of those 1,100 wells or so of undrilled inventory that you all booked as PUDs, or ballpark?

Did you hear that, Brian?

What -- no.

277.

277? Of, wow. Okay. And then I know you had some delays even though fourth quarter production was pretty good. Can you talk about what your current rate is, or what a January rate was?

Based on we know right now, it's estimated -- and let me use the word estimated, January is about 21,000 barrels a day equivalent.

Okay.

But we've recently turned some wells and in February, we have four wells that we are drilling out frac plugs on as we speak that we should be turning on the line here by early next week. So things are going to start snowballing here soon.

Okay. And then in terms of your PUDs, what did you all -- what is your average EUR for the PUDs that you all booked?

Yes, it's a hard question to answer; it's depending on where it is. I don't have that at my fingertips, to be honest with you, Brian.

Okay. And then one final one if I could. I know your goal is to get to100,000 acres, and you have gone to 80,000 acres pretty quickly. Do you see potentially getting to, say, 100,000 acres before you -- during 2014 or --? I guess, how much more acreage can you all get in -- I mean, is there a lot to still be had?

Well, we have enough money budgeted that we can get pretty close to the 100,000 acre bogey. As far as how much acreage there is to pick up from that point on, it -- there is still acreage to pick up. It -- if the Upper Eagle Ford works, there is probably one answer; if there's a different answer if it's a bigger number.

Because you could focus your release acquisition effort on if deemed to be areas where the Lower Eagle Ford is considered not very prospective, you could make it an Upper Eagle Ford play and it is a standalone. So to answer your question, we can continue to add to it, especially if the Upper Eagle Ford works. As far as what that number is, I can't tell you exactly that we can continue -- it's not indefinite, of course.

It's -- there is a limit because we bump into people on all sides of this as far as the Lower Eagle Ford. But we continue to do JVs, parties have stranded acreage at those locations and it's not insignificant. We've added quite a few locations just by forming JVs with some fairly large folks. But we feel we can easily get to 100,000 acres, and we can go past 100,000 acres, and we can easily go past 100,000 acres if the Upper Eagle Ford works.

Okay, thanks guys.

Thank you.

Adam Michael, Miller Tabak.

Hi, good morning, guys. So I was wondering if I could just get your general thoughts? I know you're still picking up acreage at a pretty attractive price. But how does management look at years of drilling inventory and balancing that versus accelerating drilling?

Well, it's something we internally discuss all the time, with having that kind of inventory. Once you get out beyond five years or so, you're not really adding a lot of present value per se. There's a case made that we should try to accelerate it. There's probably some things we'll wait and see as far as what happens as far as how our asset sales go.

But at this point in time, financial discipline is also important to us. We want to take this conservatively and get some assets sold and see what kind of proceeds we get with those sale of assets, especially since gas prices are up and there may be another decision-making point.

Also, the oil transportation, oil gathering line, that will get on the market soon. So, a combination of everything, we'll sit back and look at it and see if it makes sense for us to consider ramping things up again.

Okay, and then if I could follow-up with a question on the Upper Eagle Ford. Is the oil contribution, does the commodity mix look pretty similar to the Lower Eagle Ford on that first well?

Yes, it is; it's very similar.

Okay, thanks, guys.

Thank you.

(Operator Instructions)

Biju Perincheril, Jefferies.

Good morning. I have a couple of questions --

Biju, you need -- I can't hear a word you're saying. I don't know if you're on a speakerphone or what. I can't hear you.

Can you hear me now?

Yes.

Going back to that first Upper Eagle Ford well. Is there a way to determine whether you're getting contribution solely from the Upper Eagle Ford, or if it's previously from both fronts?

Well, at this time, we don't know that answer. I mean, that's the purpose of this well house and pad test, one upper, one lower. It's also with the Martinson pad that we mentioned. We have one existing Lower Eagle Ford well.

We're doing the Upper Eagle Ford and then we have an adjacent Martinson #3 that will also be Lower Eagle Ford so we're going to have an Upper Eagle Ford between two Lower Eagle Ford. So with the well house and the Martinson test, then I think that should be able to answer that question, but at this time, it's very difficult for us to say definitively that it's a separate reservoir.

Got it. And then I -- you had -- I think you mentioned some refinements to your type curve, early time production for some of the down-spaced wells. Can you quantify that?

Well, even though after IP rates of the adjacent wells have been very similar, there is a case to be made that maybe the initial decline rates of those wells are steeper. So we have made that adjustment just because -- and we don't have a lot of information, you have got to remember, to support that or lack thereof.

We still feel, even based on the test that John mentioned in his part of the presentation about the Cusack wells, that it doesn't appear to be any communication between all four of those wells and two of those wells are already existing wells that have been there for almost a year. So I can't tell you for sure.

We've got to get another year or two of information in our belt. But just to be somewhat conservative, we have increased the initial decline rate of the down-spaced wells just to take that into account. But that will be an ongoing adjustment as we get additional information.

You've got to remember, with the cash on cash pay out of these well of about two years, regardless of what kind of declines you have early on, since you pay these things out pretty quickly, it does not have a very significant effect on rate of return. We've done the sensitivity.

Okay, so that one just seems more sort of conservatism on your part as opposed to production data that you're observing?

That's correct.

Okay, okay. Great, that's all I had.

All right. Thanks, Biju.

Gail Nicholson, KLR Group.

Hi, Gail.

Good morning. On the Cortez' infill drilling tests, what were the lateral lengths of the infill test versus the parent wells? Are they the same?

John.

No, the two outside wells, the two parent wells were on the order of, let's see here, they were 4,150 feet on one of them and 4,450 feet on the other, and the infills were slightly longer. I don't have their lateral lengths in front of me, but the infill lengths were longer.

And then, did you see -- I mean, I know some of the other basins and when operators, during infill drilling when they shut the other parent wells in and then they bring those parent wells back on, they've seen improvement in the original parent wells from a production standpoint. Did you notice any of that in those two parent wells?

Well, you're right. We shut those wells in while we're drilling the laterals of the new wells. But what we saw when we got everything turned back on was initial high flush water production on the parent wells. They've been back online for less than a week, so we don't know where they're going to settle and how long, but they are producing as well as the two new wells still unloading a tremendous amount of frac water. And we'll probably see in some of that flush water in the parent wells, as well.

Okay. And then just lastly, looking at the leasing activity -- looking at the January presentation, the map of the leasing activity as of mid-October 2013, the majority of that activity really has been south of Shiner. The additional acreage that was acquired since mid-October, is that kind of in the same area? Or are you guys exploring new areas to lease, or what's the thought there?

John, correct me if I'm wrong, but I think most of that leasing was continuing to be in the south of Shiner, even though we have done some things northeast of Shiner.

That's correct. And as well as several bolt-ons in and around Shiner directly to the east of it.

Okay, great. Thank you very much.

Thank you.

Kim Pacanovsky, Imperial Capital.

Good morning, guys. Hi. What are some of the issues with that final settlement amount with Magnum Hunter?

Kim, this is Steve. We're just -- we're in arbitration. We're just trying to get it worked out. It will probably be a couple of months until we get it all worked out, but one thing we both -- both parties agree to is that $26 million. So we feel fairly confident that that is a minimum number.

Minimum number, okay, great. And then just a question on your rig contracts. Obviously, the economics of the walking rigs are significantly better.

I'm just wondering, what timeline do you have on your contracts? And how many walking rigs you do have out of the total? And what is the availability like? I'm sure that they're in high demand.

Well, we have six rigs currently working for us; three of them are walking rigs. Of the six, four are on term contracts of approximately a year remaining, and two are -- one of the remaining two is on a well-to-well contract, and the other one is in a middle of a six-month contract.

Are those two on the well-to-well contracts, are those walking rigs?

No, they're not.

They're not. Okay, okay. And then, just finally on the Upper Eagle Ford, as you're still trying to add acreage, are there any plans to hold results on that well as you firm up your acreage position?

I guess we'll wait and see what the results are.

(laughter) Good answer. All right. That's all I have for now. Thanks, guys.

All right. Thank you.

Sean Sneeden, Oppenheimer.

Hi, good morning. Thank you for taking my questions. Steve, just quickly for you, with you guys adding a sixth rig in Eagle Ford, can you talk about how that might impact your ability, if at all, to reach cash flow neutral? I think you guys have talked about maybe a late 2015 type of event.

Yes, sure. We were -- it's probably more of a 2016 event now. I think that the way we are looking at it with the ramp-up in the activity, we would probably be able to fund about a $500 million program, going into 2017 at cash flow neutral. So we're thinking probably that -- towards the end of 2016, Sam -- excuse me, Sean.

Sure, that's helpful. And then could you talk a little bit about your Marcellus assets? I think you've said that you're planning to sell the Mid-Continent Selma Chalk. But did that ever -- and I know it's not a big number, but did that ever kind of come across divestiture target?

Well, it's always on the list to get rid of if somebody is interested in it. We're time-consumed with where it is and it's dry gas; it just hasn't gotten on anybody's radar screens. I mean, we've got three wells producing; in total, we're making about 0.5 million BOE a day. It's just really, it's just a project that is falling apart.

Leases are expiring. So in the next two to three years, most of our acreage will be gone other than just the acreage that we have earned with those three PDPs.

Okay. And then last question, you talked about and then -- I know discussed you've discussed this in the past, but your non-op partner, Hunt. Can you talk about any -- what's going on there in terms of what they're thinking and is there any opportunity for you guys to essentially get acreage from them?

Well, we have some acreage that we operate that they're about a 50% owner, them and Marubeni. So they're very extremely pleased with the results on the acreage that we operate and the wells that we drill on that acreage. At this point in time, we still retain the rights to proposed wells on the acreage that they operate. But they -- we have no reason to think that they're going to resurrect any drilling on their operated acreage.

Okay, that's helpful. Thank you very much.

You're welcome.

Thank you. [Frances Kahn], Private Investor.

Thank you. Hi, guys, congratulations again on your stock going in the right direction. I've been involved in it in both directions and you've done a fine job turning it around. I have a very simple question, if you'd answer it to the best of your ability, with GeoSouthern getting bought out by Devon and Baytex getting Aurora.

With you guys are in the cross hair, I'm quite sure, if somebody comes knocking, are you guys interested or are you going to say nobody is at home? How does the Board feel and how do you guys feel as insiders?

Well, we always have to listen if someone were to knock on our door. We'd have to listen, of course, to what they're offering or proposing. We feel because of what we're doing and because of our recent results, that we can -- we have more value to get out of our current position as to the shareholder.

So at this point in time, we think it would be premature to consider selling our Eagle Ford position or selling the Company, considering we think we've got a lot of room to grow value. But you always have to listen and those kind of metrics that you mentioned are certainly very, very encouraging, of course. So other than that, that's really all I know, and all I can say because that's how I feel.

I appreciate that, Baird. I've been in the stock a little bit after 1882, just shortly after that. So maybe it's time we all go home and sell the thing. But anyway, I appreciate your answer.

Thanks, Frances.

Bye bye.

Thank you. I'm showing no more questions at this time. I would like to turn the call over to Mr. Whitehead for closing remarks.

Anyway, thanks for listening. We have given you a lot of detail. I think one thing I -- you can see here is operationally, things are clicking very well for us. And you need that strong foundation to grow a Company.

And we think we're in that situation right now. So you would expect, based on what we're doing and the results we're seeing, that we would expect production and cash flow growth to continue to follow accordingly. So look forward to it, going through our first-quarter 2014 call with you all and have a good day.

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