Penn Virginia's CEO Discusses Q4 2013 Results - Earnings Call Transcript

Feb.20.14 | About: Penn Virginia (PVAHQ)

Call Start: 10:00

Call End: 11:00

Penn Virginia Corporation (PVA)

Q4 2013 Earnings Conference Call

February 20, 2014 10:00 AM ET

Executives

Baird Whitehead - President and CEO

Steve Hartman - CFO

John Brooks - COO

Analyst

Neal Dingmann - SunTrust Robinson Humphrey

Brian Corales - Howard Weil

Adam Michael - Miller Tabak

Biju Perincheril - Jefferies

Gail Nicholson - KLR group

Kim Pacanovsky - Imperial Capital

Sean Sneeden - Oppenheimer

Operator

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 being recorded.

I would now like to turn the call over to Mr. Baird Whitehead, President and CEO. Please go ahead.

Baird Whitehead

Destiny, thank you. I would 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 that the language in our forward-looking statement sections of the press release is 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 remain strong and as reflected in the table in our operations update we drilled some very-very good wells with the highest IPs in 30 day raise of any well since inception of our activity in the Eagle Ford.

Some of the highlights for the fourth quarter and year-end include; proved reserves right now are 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 a 45% oil and 16% NGLs; 40% developed with the PV-10 of about $1.7 billion. Year-end 2012 our proved oil percent was 22%, NGLs were 18% and 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% 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 if there had not been some delays in completion internalizing the fourth quarter that were pushed into early into the first quarter 2014.

Fourth-quarter product revenues were $117 million or approximately $64 per barrel oil equivalent which is a 4% decrease in 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 [revised graph] 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 non-recurring G&A items that Steve will discuss in more detail here soon. Operating income was approximately $15.5 million which compares $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, our adjusted net loss was $6.7 million or $0.10 per diluted share compared to the adjusted net loss of $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 with the wells that 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 drivers of increased production in cash flows in 2014 is an Eagle Ford drilling program that is focused on gas-based wells, multi-well pad drilling and zipper fracs in areas that we anticipate excellent results based to a large extent that 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. And you can certainly see in the table in the operations update that we had 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 we expect 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 80,000 net acre now. Our near-term goal remains at a minimum 100,000 net acres in a field at this time, we should be closer to this goal by the end of the year with a capital dollars allocated in the budget through leasing acquisitions.

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

We continued to add significant value to the company with attractive lease acquisition cost that at a snapshot in time now represents a drilling inventory of over 10 years based on our current activity level. We only expect to add to this inventory with further acreage additions, on-going success in down spacing and potential success in the upper Eagle Ford. And speaking of the upper Eagle Ford in the press release we discussed the status of our most current test, referred to this as the Welhausen pad. We just ramp production casing on this upper Eagle Ford test well. The lower Eagle Ford offset was driven in case in January.

As discussed in the past our goal now is completing both of these wells to test the upper and lower and to see if they impact our separate reservoirs. Completion should begin shortly on both these wells without these expected probably later on in March.

In addition we have spread a subsequent upper Eagle Ford well approximately two miles of 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 on-going tests that we have this question answered by the middle of this year. And in addition this will help us determine the potential of the upper Eagle Ford as a standalone reservoir and help direct our leasing activity were 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 lit assets, and received about $94 million net to our working interest. As a result of our pro forma financial liquidity as of December 31st, 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 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 he’ll fund our 2014 spend. Steve will get into some more detail concerning liquidity here in a minute. So with that I’d like to go ahead and turn this call over to Steve.

Steve Hartman

Thanks Baird and good morning. I’ll start with a 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 Eagle Ford. This was offset by continued improvements in compression expenses as we rationalize 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 $10.0 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 cost related to recent accounting system implementation and acquisition audit fees. Excluding these non-recurring 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 space restricted to 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 unit starts resting in 2015.

Companywide operating margin as described in our earnings release was $47.7 per barrel of oil equivalent, the non-cash and non-recurring G&A items I just described decreased this margin by about $2 per barrel of oil equivalent which were 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 our indicated G&A. Adjusted EBITDAX and non-GAAP measure reconciled on page 9 of the release was $84.4 million for the quarter compared $88.3 million in the third quarter. A 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 expense, 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 $6.7 million for the year and other adjustments reconciled on page 9 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 where 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 have completed and turned in line all wells that we are planning 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 carry over. Moving onto 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 gathering sale to American Midstream for gross proceed of a $100 million. Including purchase price adjustments and pay outs to working interest partners, we had net cash proceeds of 98.4 million. Pro-forma for the asset sale of 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 that’s permitted in our credit facility is 342.4 million for the trailing 12 month period. Pro-forma for the asset sale of proceeds, our year end leverage was 3.5 times.

Moving on to hedges, we have been very active in adding swaps and collars to oil portfolio for 2014 and 2015. We currently have 10,000 barrels a day of oil hedge 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 ‘15 and 5,000 barrels per day for the second half of ‘15. 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 onto our 2014 guidance update which is detailed on page 10 of the release. Our guidance does not include the potential sale of Selma Chalk and Granite Wash assets that are currently in market. If and when we sale those assets, we will update guidance accordingly.

We are planning to run a six rig operative program with all drilling taking place in the Eagle Ford. We plan to drill approximately 98 gross and 53 net wells and we will turn in line a similar number of wells through the year. We alternatively run three rigs in Gonzales County and three rigs in Lavaca County. And there is a table on page five 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 a carryover on our well contingency cost, 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, emphasize development near recent excellent well results in the Shiner area with higher GORs some turning line delays early in 2014, adjustments to the early time performance of the type curve associated with down spacing, increasing the offset well shutting assumption related to zipper fracking, increasing the number of days for flow back and clean-up of multi well pads, so it’s now we’re drilling as much as four wells per pad. And this overall decrease is offset by better well results expected from increasing the number of frac stages and in putting the way more profit per stage.

As we’ve 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 in model, 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 oils growth which we’re 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 LOS basis differential, $7 off of that for transportation which makes WTI less $2 for our realized oil price in 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 higher contribution of oil production and higher compression charges related to the Eagle Ford gas gathering system sale. Our 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 ’13. 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 $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 and 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 yearend 2014 will 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 settlement amount is still being finalized and given we receive this money in 2014 our liquidity would be at least $200 million at year end. Also at year end our leverage would be about 2.9 times to 3 times debt adjusted EBTIDAX.

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 will continue to improve and end the year at about 2.7 times to 2.8 times debt to adjusted EBITDAX and we would fund the outspend a 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.

John Brooks

Thanks 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. And 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 52% in the third quarter. Despite this growth and be 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 the number of wells quarter later in December and January as Baird and Steve mentioned.

Currently we have a 179 Eagle Ford Shale producing wells. We have 13 operated wells completing or waiting on completion and two outside operated wells waiting on completion and six 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 averages are markedly better than our previous report.

The average lateral links for these 23 wells was approximately 5,700 feet 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 a higher concentrations of proppant 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 in these frac efficiencies and therefore overall production rates. 22 of these 23 recently drilled wells were drilled off at 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 proppant concentration per frac stage appears to be working extremely well. With respect to proppant in the fourth quarter we pumped an average of 7.9 million pound of proppant 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 was also in an average of between 1,300 and 1.400 pounds of proppant per foot of lateral.

In the fourth quarter we completed 19 wells with average total well cost of approximately 9.51 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 cost per frac stage in the third quarter and that compares to roughly $440,000 during the second quarter.

In terms of purely stimulation cost rather 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 in the 30 day average gross production rate per frac stage was 45 BOE per day, increases of 18% to 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 consist of 225 fluid stage spacing with five perforation clusters per stage and pumping about 300,000 pounds of proppant, maintaining the 1,300 to 1,400 pounds of proppant per foot of lateral. We think this covers an additional 10% to 15% more of the lateral pay section increasing overall stimulator 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 it further reduces water, chemical and pump times all the while placing more sand in the formation in maximising SRV.

We are using over a 100 mesh on the frontend to improve overall fracture complexity followed by white sand and then we tail in with a resin coated proppant, this not only reduces the cost but also reduces or even completely eliminates the proppant flow back while providing the advantage of a proppant attack with a higher rated closures stress.

Our stimulation design continues to evolve as we more tightly engineer our fluids and pumping schedule to further increase the amount of proppant pump 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’re also achieving some additional efficiency gains from the pad drilling whenever possible we used a lot of those walking rigs to further reduce rig release to spud cycle time and the use of smaller spudder rigs to pre-set surface casing on multi-well pads. We’re able to combine the pre-set 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. And even without a full year benefit of using the spudder rigs with the walking rigs our drilling team continues to reduce our drilling cycle time and cost. Not to mention that we’re drilling deeper wells with longer laterals compared to 2012 our drilling cost per foot in 2013 was reduced by 18% in Gonzales County and 24% in 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 -- all adds up to four consecutive quarters of declining per stage total well cost, even though we’re drilling longer laterals completing more frac stages and achieving more productivity per stage.

Now 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. The 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 on our recent IP table. Primarily because like I said the lower reservoir energy associated with lower GORs and relatively shallow PVD. These two wells laterals were drilled 400 to 500 feet apart, but also importantly we’re located in between two existing Eagle Ford shale wells. The two older parent wells have 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 infield wells drilled a year later is 1,812 BOE per day. So I still review this as an encouraging data point in the down spacing aspect of our plan of development. Then we drilled two successful infield wells between two material producers and we’re seeing similar rates 1,812 BOE versus 1,896 BOE per day at similar well head 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 line 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 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 cost of between 8.1 to 9.6 million and average pre-tax rate of return of 50% to 60%.

Having said that we believe our most recent wells may exceed these excellent economics but we’ll need more time to confirm that.

Lastly as Baird mentioned we remain enthusiastic with the potential of the upper Eagle Ford shale interval, we have just ramp production casing on an upper Eagle Ford test well our Welhausen A2H, which along with the adjacent lower Eagle Ford shale well Welhausen B1H should be completed sometime in March.

Furthermore we’re 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 Fojtik had accumulated roughly 85,000 BOE during its first 292 days. And we think that’s a good performance giving a short lateral 4,200 feet in only 17 frac stages and fairly light frac intensity is only 240,000 pounds per stage. By comparison or upcoming Welhausen A2H will have 27 stages and a lateral length of 6,000 feet?

Assuming these test 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 dealing in completions during 2014 and beyond. Fairly in this situation the potential additions to our drilling inventory and value could be significant.

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

Baird Whitehead

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

Question-and-Answer Session

Operator

(Operator Instructions). Our first question comes from the line of Neal Dingmann of SunTrust. Your line is open.

Neal Dingmann - SunTrust Robinson Humphrey

Had a question obviously on these last 23 wells your IP as well as the 30 day rate continues to improve dramatically. I am just wondering going forward are we going to start to see that sort of level off a bit I mean is this just because of sort of the drilling completion technique and longer spacing all that that were used or how much more improvement can we continue to see?

Baird Whitehead

Neal that’s a difficult question to answer of course. I mean I think that everything we mentioned as far as spacing and zipper fracs and some of the refineries that John mentioned that’s clearly added to the potential we’re choosing increased IPs. As far as whether we continue to do that we will probably start continuing to see some sudden increases that 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 barrel per day, barrel oil per day rates alone plus NGLs and gas, we’d be extremely happy. And we’ve not really baked that into or our production forecast for the year we’ve been somewhat -- we’ve tempered our enthusiasm until we get some more results behind us but there clearly is some upside in where we would expect production to be for the year if we continue to drill wells as we’re sort of in the same ballpark as -- or some of these other wells we had shown in the ops update.

Neal Dingmann - SunTrust Robinson Humphrey

Okay. And then one follow up if I could, just Baird, on the upper Eagle Ford I know I think there is third, one type of gym sounds like it’s the only bit longer lateral few more stages. Your thought I guess on if you sort of how much more improvement we might see on this one versus maybe the first one that was reported and then secondly any thoughts on just how much of your acreage is perspective for the upper Eagle Ford.

Baird Whitehead

Well the only thing I can tell you at this time it gives some encouragement on a well [has in] 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 the performance but you clearly would rather have good [mud lock shows] than that. And 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 that the slide tech which was our original well there is some that you remember I think the reason that we had said that we thought ultimate reserve is on that well is about 380,000 barrels. At year end because of how this thing is actually sort of some because I level that, we actually booked 450 on it and that’s [aside] reservoir engineer number.

So it does give us some comfort that the flies take well 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 sort of answer it directly because I don’t know the answer at this time but again we’ve got to get this well [high and pad] completed we go get the Martinson pedal completed, actually the Martinson is one well the existing well lower Eagle Ford in that pad, if I’m not mistaken, is over a 700,000 barrel ultimate well, so it's in a good area. So we’re pretty enthusiastic about what we’re doing on a lower and the upper end. But if we can have some positive indicators early on at upper Eagle Ford we consider the homerun and we had a lot of finish to do and give us some flexibility on moving locations around and moving our joint program around if it’s deemed that it makes a lot of sense to do that. So it certainly opens up a lot of opportunities for us.

Operator

Thank you. Our next question comes from the line of Brian Corales of Howard Weil. Your line is open.

Brian Corales - Howard Weil

Hey guys. One question on the inventory, it was a nice increase. Can you tell us what you’ve booked? How many those 1,100 wells or so of undrilled inventory that you’ll book is PUDs or a ballpark?

Baird Whitehead

Did you hear that Brian?

Brian Corales - Howard Weil

Well, no.

Baird Whitehead

277.

Brian Corales - Howard Weil

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

Baird Whitehead

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

Brian Corales - Howard Weil

Okay.

Baird Whitehead

But we’ve recently turned some wells in February. We have four wells that we are drilling at frac flow is on as we speak that we should be turning lines here by early next week so things are going to start snowballing here soon.

Brian Corales - Howard Weil

And then in terms of your PUDs, what is your average EUR for the PUDs that you have booked?

Baird Whitehead

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.

Brian Corales - Howard Weil

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

Baird Whitehead

Well we have enough money budgeted that we can get pretty close to the 100,000 acre bogey. As far as how much acres there is to pick up from that point on, there is still acres to pick up. If the Upper Eagle Ford works, there is probably one answer. It’s a different answer. It’s a bigger number because you could focus your released acquisition effort on, if being to be areas where the Lower Eagle Ford is considered not very perspective, you could make it an Upper Eagle Ford play and it’s 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. There is a limit because we are sort of bumping the people on all sides others as far as lower Eagle Ford but we continue to do JVs.

Parties have stranded acres that adds locations and it’s not estimate. Again, we have added quite a few locations just by forming JVs with some fairly large folks. But we feel we can easily get to 100 and we can go past a 100 and we can easily go past the 100, if the Upper Eagle Ford works.

Operator

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

Adam Michael - Miller Tabak

So, I was wondering if I could just kind of get your general thought, I know you are still picking up acreage at a pretty attractive price but how does management kind of look at years of drilling inventory and balancing that versus accelerating drilling?

Baird Whitehead

Well it’s something we internally discuss all the time with having that kind of inventory, once you get up on beyond five years or so, you are not really adding a lot of present value per se. There is a case made that we should try to accelerate it. There is probably some things, we will wait and see as far as what happens, as far as how our asset sales go. But at this point of time, financial discipline is also important to us. And we want to take this conservatively and get some assets sold, see what kind of proceeds we get with those sale of assets especially since gas prices are up. And there maybe another decision making point, also the oil transportation, oil gathering line that will get on the market soon. So, a combination of everything, we will sit back and look at and see if it makes sense for us to consider ramping things up again.

Adam Michael - Miller Tabak

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

Baird Whitehead

Yes, it is, it is very similar.

Operator

(Operator Instructions) Our next question comes from the line of Biju Perincheril from Jefferies. Your line is open.

Biju Perincheril - Jefferies

Yes, going back to that first Upper Eagle Ford well, is there a way to determine whether you are getting contribution solely from the Upper Eagle Ford or if it’s producing from both sides?

Baird Whitehead

Well at this time, we don’t know the answer. I mean that’s the purpose of this well as in a pad test, one upper, one lower, it's also with the Martinson pad we mentioned we have one existing Lower Eagle Ford well. We are drilling the Upper Eagle Ford and then we have an adjacent Martinson III that will also be Lower Eagle Ford. So, we are going to have Upper Eagle Ford between two Lower Eagle Ford, so what the well has in a 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 definitely that it’s a separate reservoir.

Biju Perincheril - Jefferies

Got it. And then you mentioned some refinement to your pipe curve early time production for some of the down space wells, can you quantify that?

Baird Whitehead

Even though the IP rates of the adjacent wells have been very similar, there is a case in May 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 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 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 on 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 got to remember with the cash on cash parity of these well is of about two years. You know 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 that sensitivity.

Biju Perincheril - Jefferies

So that adjustment seems more sort of conservatism on your part as opposed to a production data that you are observing?

Baird Whitehead

That’s correct.

Operator

Our next question comes from the line of Gail Nicholson of KLR Group, your line is open.

Gail Nicholson - KLR group

On the [quotas and drilling path] what was the lateral length of the infill path versus the parent, wells, is it the same?

Baird Whitehead

No, the two outside wells, the two parent wells were on the order of, 4150 on one and 4450 on the other, and the in-fills were slightly longer. I don’t have their lateral links in front of me but the infill links were longer.

Gail Nicholson - KLR group

And then did you see -- I know some of the other basins with operators doing infield drilling when they shut the feed, other parent wells in and then they bring this parent wells back on, they’ve seen improvement and then the original parent wells are on a production standpoint, did you notice any of that in those two parent wells?

Baird Whitehead

Well you’re right we shut those wells in while we’re drilling the laterals of the new wells, and what we saw when we got everything turned back on was initial high flush water production on the parent wells. They have been back online for less than a week. So we don’t know where they are getting to settle out on, but they are producing, as well as the two new wells, still unloading commence it's not a frac water and we're probably seeing some of that flush water in the parent wells as well.

Gail Nicholson - KLR group

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? Are you guys kind of exploring new areas to kind of leased or, what’s the thought there?

Baird Whitehead

John, correct me if I’m wrong, but I think most of that leasing was continued to be in south of Shiner even though we have done some things north east of Shiner.

John Brooks

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

Operator

Our next question comes from the line of Kim Pacanovsky of Imperial Capital; your line is open

Kim Pacanovsky - Imperial Capital

What are some of the issues with that final settlement amount with Magnum Hunter?

Steven Hartman

This is Steve. We are just -- we are in arbitration with, we’re just trying to get it worked out, it will probably be a couple of months till we get it all worked out. But one thing we both parties agree to is that $26 million, so we feel fairly confident that that is a minimum number.

Kim Pacanovsky - Imperial Capital

And then just a question on your rig contracts; obviously the economics of the walking rigs are significantly better. I’m just wondering what kind of timeline 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 they are in high demand.

Baird Whitehead

We have six rates currently working for us. Three of them are walking rigs. Of the six, four are on term contracts of approximately a year remaining and 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.

Kim Pacanovsky - Imperial Capital

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

Baird Whitehead

No they are not.

Kim Pacanovsky - Imperial Capital

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

Baird Whitehead

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

Operator

Our next question comes from the line of Sean Sneeden of Oppenheimer; your line is open.

Sean Sneeden - Oppenheimer

Steve, just kind of quickly for you; you guys are adding the sixth-grade bearing 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 late ‘15 type of event.

Baird Whitehead

Yes, sure, it’s probably more of a 2016 event now. I think that where we’re looking at it with the ramp up in the activity, we will probably be able to fund about $500 million program going into ‘17 at cash flow neutral. So we’re thinking probably that towards the end of 2016, Sean.

Sean Sneeden - Oppenheimer

Sure that’s helpful. And then I guess can you talk a little bit about your Marcellus assets? I think you said that you are planning to sell the Mid-Continent, but does that ever -- I know it’s not a big number but has that ever kind of come across the best to target?

Baird Whitehead

Well it's always on a list to get rid of if someone is interested in it and we see where it is and its dry gas. It just hasn’t gotten on anybody’s radar screen. So I mean we've got three wells producing until they are making about 0.5 million a day, is just really 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.

Sean Sneeden - Oppenheimer

And then just kind of last question. You talked about, I know you have 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 are thinking and is there any sort of opportunity for you guys to eventually get acreage from them?

Baird Whitehead

We have some acreage that we operate. They are about a 50% owner in Marubeni. So they are very extremely pleased with the results on the acreage that we operate in the wells we drilling at on that acreage. Additionally we still retain the right to propose wells on the acreage that they operate, but we have no reason to think that they are going resurrect any drilling on their operated acreage.

Operator

Thank you. And our final question comes from the line of [Francis Con] a Private Investor. Your line is open.

Unidentified Analyst

Hey guys congratulations on getting the stock going in the right direction. I have been involved in it in both directions and you have done a fine job turning it around. I got a very simple question, if you'd answer it best as your ability. With GeoSouthern again bought out by Devon and they take getting out of our. Are you guys in the crosshair, I am quite sure if somebody comes knocking are you guys interested or you are going to say nobody’s at home? I mean how does the Board feel and how do you guys feel as insiders?

Baird Whitehead

We always have to listen if somebody would knock on our door, we’d have to listen of course to what they’re offering or proposing. We feel because what we’re doing because of our recent results 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 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 it's how I feel.

Operator

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

Baird Whitehead

Anyway thanks for listening. We have given you a lot of detail. I think one thing you can see 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’ve seen that we would expect production and cash flow growth to continue to follow accordingly. So look forward to going through our first quarter 2014 call with you all and have a good day.

Operator

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

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