Penn Virginia Corporation
Q4 2014 Earnings Call Transcript

Published: 26 Feb 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation Fourth Quarter 2014 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 follow at that time. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference call Baird Whitehead, President and CEO. Sir, you may now begin.

[Baird Whitehead:]

All right, thank you very much, and thank you for joining us today for Penn Virginia's fourth quarter and year end 2014 conference call. As always I am joined today by members of our management team, which includes John Brooks, our Chief Operating Officer; Nancy Snyder, our Chief Administrative Officer; Steve Hartman, our Chief Financial Officer; and Jim Dean, our VP of Corporate Development. Prior to getting started, we would like to remind you of the language in our forward-looking statements, sections of the press releases issued yesterday as well as K, which we filed last night. We changed our talk little bit this time, there is actually a presentation out there on the web that we will go through simultaneous through the call. First slide, I am going to address a little later, our production variance in the fourth quarter as compared to guidance, but we have some significant accomplishments during the year that we think will provide longer term benefits to this Company. Our Eagle Ford production reached record levels in the fourth quarter and was 33% higher than the fourth quarter of 2013. Progress in working off is significant. Completion inventory during the fourth quarter is beginning to provide production growth we had expected, and now you're starting to see that sharply higher total company production in January at 25,200 barrels equivalent per day with all that growth coming from the Eagle Ford which averaged almost 22,000 barrels a day in January. We ended the year with internal estimated reserves in the Eagle Ford of over 1 billion barrels equivalent, which is about 260% increase from last year with an associated PV10of about $3 billion. We also ended the year with Eagle Ford crude reserves of 94 million barrels equivalent, which is 24% higher than last year and has a PV10 of $1.4 billion. We increased our net acreage position in Eagle Ford by approximately 30% since last year to its current position of 102,000 net acres. With a dedicated effort of testing and understanding the potential of the Upper Eagle Ford, we feel that we now have successfully de-risked this new play type with the total of 20 wells drilled and completed to-date with excellent average results. We also feel and are confident. Even though we are still early in collecting production data that the upper and lower Eagle Ford are acting as separate reservoirs. In our operations release of last week, we announced 2015 CapEx program that is 60% lower than 2014. We have reduced our rig count from eight, which we had drilling at mid-December, to a current rig count of three which we reached just a week ago. The intent is to run these three rigs through remainder of the year. With oil prices that are 50% less than what they were just six months ago, we are focused on maintaining healthy levels of financial liquidity and simultaneously focused on drilling our highest return wells in this lower cost environment. Our overall production growth associated with this lower CapEx program will result in a growth of 10% to 20% overall company, while pro forma for the sale of our Mississippi assets and some litigation settlements through the third quarter we had from our Mid-Continent assets. We expect that pro forma growth to be 17% and 29% with 30% to 40% growth in Eagle Ford by itself. With the liquidity steps we took during 2014 including the sale of our Eagle Ford gas gathering and crude gathering systems, the sale of our Mississippi assets and the $325 million of convertible preferred equity, we ended the year with liquidity of about $470 million, which is nearly double which we had at year-end 2013. Next slide, production for the fourth quarter was 21,300 barrels a day equivalent of which 17,500 barrels equivalent was from the Eagle Ford including the benefit of our strong hedge position in fourth quarter product revenues were $112 million or $57.03 per barrel equivalent. We're also making progress in reducing our production cost; LOE, gathering processing and transportation and production tax expenses decreased from $28 million or $13.35 per barrel equivalent in the third quarter to $23 million or $11.52 per barrel equivalent or a decrease of about $1.80 per barrel equivalent. The initial potential rates for Eagle Ford wells completed since the third quarter averaged 1,226 barrels equivalent per day with a corresponding 30-day rate for the appropriate wells of 937 barrels equivalent per day. The recent average IP is slightly less than what we reported in the third quarter but more encouraging and promising is the 30-day rate was actually higher than what we experienced in the third quarter. Later we will give you a lot of data on the overall Upper Eagle Ford program, but we continue to make progress in demonstrating success in the Upper Eagle Ford. We now believe that approximately 80% of our overall Eagle Ford acreage position we think is now prospective in the play with over 1,800 Upper Eagle Ford locations by itself. Next slide it tends to explain a variance we had on our fourth quarter production is compared to gas. I know there was a meaningful shortfall. But most of it was associated with the large inventory completions, we had due to the active drilling program that we had at the time with eight rigs drilling. Candidly, delays in additional offset shut‐ins required were higher than we had anticipated with the total of about 3,600 barrels a day equivalent shortfall allocated to those two categories. Most of this was associated with our active completion program in the Welhausen area, where we had drilled previously some very good upper and lower wells and we offset these very good wells. But due to this high completion activity, we had some unforeseen delays and because of interference we had between wells and one of the frac operations itself we had to show some of the previously completed wells in. The other category of mechanical issues was about 1,000 barrels a day and was primarily associated with two Hinze wells and one Netardus well. Those operational issues were ultimately resolved, but this slowed things down somewhat or restrict production for a period of time. One point that is important to mention that there is not a bar for any performance issues and that's because we didn't have any. You always have some wells that do better than you would expect, some wells to do worst but overall this was not an issue in the fourth quarter variance. But if you look at the January 2015 production, we have recovered much of that fourth quarter daily production shortfall. For comparison purposes also shown as what we had provided for the first quarter production guidance. And at this time, we are confident that our first quarter production will be within that range. Sixth slide gives a lot of detail concerning what we hope to get accomplished in our strategy in 2015. Most importantly is to preserve financial liquidity and our Eagle Ford acreage position. At the end of the year, we had about $470 million of borrowing base liquidity, but we would expect that our 500 million borrowing base to be impacted by about 20% or $100 million for our spring redetermination as the banks use lower-priced decks. But even taking that into account, while along with the anticipated 2015 spend of $150 million to $190 million, we expect and will take steps if necessary to remain below our four times covenant level. Steve Hartman will get into a lot more detail of this later on the call. Even though our lease acquisition effort has been reduced significantly in 2015 where we spent almost $100 million in 2014, we still selectively will continue to acquire new leases to firm up our proposed drilling units or expand our acreage based on new drilling results. A dollar of leased acquisition capital goes a lot further today than what it did at this time last year since acreage cost have come down from around $3,500 an acre to about $1,500 an acre today. In spite of the 60% reduction in CapEx year-over-year, we still expect annual production growth of 10% and 20% as 17% to 29% pro forma with most of that production growth and spending occurring in the first half of the year with fairly flat subsequent quarterly production in the second half of the year. We will invest our CapEx dollars in our highest return development areas, which we think now include our Upper Eagle Ford with almost 20% returns expected based on our flat $55 per barrel oil price. The Shiner Beer Quad area of along those 20% returns and the Gonzales Peach Creek, Rock Creek areas with returns over 25% due to the lower drilling and completion costs. Importantly, our goal will be to reduce not only our drilling and completion costs, but also to reduce our leased operating expenses further as the year progresses. These additional cost reductions have nothing built into our current budget or guidance, so review any benefits to those as potential upside as the year progresses. John will get into a little bit more detail as to how we expect to accomplish that as the year moves along. But if we can be successful in getting our well cost down to additional $1 million, which is about 15%, our Upper Eagle Ford and Shiner, Beer Quad returns would increase to almost 30% and our Gonzales, Peach Creek would be increased to 40%. One issue that I want to expand upon because I think there is some confusion is our drilling and completion cost include almost $500,000 for surface facilities, asset tank batteries, your low-pressure separator, heater/treaters things of that nature. Not all of our peers include these facility cost in what they report for drilling and completion cost, and this is something you need to be aware of since these surface facility cost are a significant percentage of our reported drilling and completion cost. The next slide I’m not going to spend a lot of time on, but the slide tells a good story all by itself; with a 6% decrease in terms of CapEx from $794 million to $320 million year-over-year. We still expect our production to increase pro forma from roughly 20,300 barrels a day equivalent to 25,000 barrels a day equivalent were 23% increase. Not taking into account these production adjustments for 2014, we still expect production to increase 15% year-over-year. And lastly, I think it’s important to how we view our current drilling inventory. We should not take into account the total acreage position we have at 102,000 net acres and the fact that we think that we now have derisked the Upper Eagle Ford across most of this acreage. Excluding the wells drilled and producing this table shows the inventory by area and our play type. Out of the total 3,400 potential locations we have today, we now think over half of those are associated with the Upper Eagle Ford. We have typically shown a version of this table in our public presentations and based on the last presentation that we had in December, we've increased our location inventory from 1,900 locations to 3,400 locations, which of course provides a significant number of years of drilling inventory, especially with a reduced rig count. As in the past, which lends credibility, all of these 3,400 locations are actually on a map with a surface and bottom-hole locations mapped out. And typically, as part of the 3,400 locations those laterals are spaced about 400 feet apart. As you would expect with the rejection of drilling activity within approximately 60% of our acreage, HBP and Eagle Ford, we need to have a plan on how we are going to HBP the remainder of that acreage and minimize any renewals and extensions. 2015 with a reduced rig count is very manageable, and we expect minimal renewals or extensions. We only have about 4,000 net acres that are subject to renewal, the other 4,000 net acres for a total of 8,000 net acres can be extended for two years under the lease extension provisions that we have on our lease. So between our drilling program and any renewal money, which would be small or roughly $1,500 per acre, we don’t have a problem in 2015. And with that, I’ll like to go here and turn the call over to John Brooks, to give you some operational detail.

[John Brooks:]

Thanks, Baird. I’m going to flip over to Page 9, 2014 operational summary. We finished up 2014 meeting our goal of reaching the 100,000 net acres milestone, naturally exceeding that by a couple of thousand acres. It’s a highly contiguous position and substantially derisked and drill bit. And with our ongoing success in the Upper Eagle Ford, as Baird said we now have a drilling inventory in excess of 3,400 total Eagle Ford locations, assuming full development of the assets stacks pay potential. Additionally this highly contiguous nature of our acreage also gives us operational advantages relating to gathering the oil, gas, and water. We grew our total Eagle Ford production by 45% year-over-year. December’s exit rate of 18,635 BOE per day was lighter than planned, and this was due in large part to the challenge of completing all the wells that are eight-rig program generated. Lot of that completion inventory has been worked off as evidenced by January 2015 production for almost 22,000 BOE per day, which is an 18% increase over December. Also in 2014 we were targeting 400,000 pounds of profit over 225 foot stage-links. This significant increase in profit required longer pump times, resulting in fewer stages per day and linked in those cycle times. Companywide, 2014 oil production growth was 35% and we expect 2015 total Company production growth of 10% to 20%, pro forma 17% to 29%. We expect 2015 total Company oil production growth of 10% to 18%. Our year-end third-party 2014 total Company proved reserves were 114.8 million BOE, Eagle Ford proved reserves were 94 million BOE, up 24% year-over-year. Year-end internal 2014 3P reserves in the Eagle Ford were a little over 1 billion BOE, and that’s up 263% year-over-year. As Baird mentioned, we continue to have operational success across our asset in both the Upper Eagle Ford as well as the Lower Eagle Ford. We now estimate that the Upper Eagle Ford is perspective across about 80% of our leasehold with approximately 1,850 locations. Our drilling department continues to improve overall rate of penetration or ROP, and reducing days on location. For 2014, the average of all our rigs was 900 feet per day, which is a 17% increase year-over-year. We drilled 98 wells in 2014 compared to 56 in the prior year. This was 1.737 million feet, and 81% increase year-over-year. We are now operating 3 drilling rigs, down from eight, keeping our best performing rigs. Two of the three retained rigs have been retrofitted with 7,500 PSI fluid ends on their mud pumps, which yields an additional 800 PSI of hydraulic advantage allowing for further ROP enhancement. The third rig is scheduled to have its fluid ends upgraded during its next pad move. Our quickest two-stream well was drilled in 8.85 days from spud to rig release, and our quickest three-stream well was drilled in 15.73 days from spud to rig release. Our average two-stream well was drilled in 16.1 days, and our average three-stream well was drilled in 25.8 days from spud to rig release. Another change we’ve implemented is in our well design. Previously, our three stream wells were completed with 4.5 inch casing, which led to several mechanical challenges, so we’ve upsized our design to 5.5 inch casing. This also requires upsizing our surface casing and our intermediate casing, leading initially to higher cost as we put more steel on the ground. These bigger hole well designs had their own learning curves since we had sparse relevant bid records for the larger holes in the areas where we were drilling these. After drilling several of these larger well bores, however, and generating our own bid records our ROPs continue to improve and it looks like mostly a learning curve maybe behind us. The larger hole size, allows for larger directional tools, which have longer running live at the higher temperatures associated with the deeper wells in the three-stream areas. This keeps us from bottom drilling more and tripping for tools less. Besides improving mechanical reliability, one of the advantages of the bigger hole is lower intriguing pressures, while we frac, which reduces horsepower and stimulation costs. Regarding stimulation, we’re now running two frac spreads and have recently realized a 10% cost reduction on pumping services. In 2014, we were targeting 400,000 pounds per stage for 225 foot stage, and in 2015 we’re targeting 300,000 to 350,000 pounds per stage for 250 foot stage-links or 1,200 to 1,400 pounds per foot of lateral. Currently our stimulation cost is running around $100,000 per stage for 300,000 pound stage. We expect this to decline further as all of our stimulation cost pumping, prop, and chemicals continue to fall, and we expect to be below $90,000 per stage before mid-year. While generally speaking pumping more profit usually co-relates to improved production response, we had several instances where the additional profit loading did not result in materially improved production. So while it’s still early, in some instances it appears we may have reached a point at diminishing returns with regards to profit loading. This observation help guide our latest completion design with somewhat less profit per foot. We’ll continue to optimize our completion design and selectively pump higher profit loading where it makes the most sense. With regards to LOE, we’re also continuing to reduce that LOE as we illustrated in the graph at lower right on Page 9, third quarter 2014 on the LOE was $7.07 per BOE, fourth quarter was $5.82 per BOE, and for January 2015, we’re tracking around $5 per BOE. Moving to Page 10, just a complete summary of our Upper Eagle Ford results since our first well the Fojtik was completed almost two years ago. One thing that stands out is the strength of the IP30 rates exceeding 900 BOE per day. And while most of our Upper Eagle Ford wells have been drilled in Shiner in our Southern more down-dip acreage, we recently completed the Dingo pad, which is at the Northern up-dip end of our acreage in Peach Creek near the triple junction of Gonzales, Lavaca and Fayette counties. The Dingo pad is a three well pad with two lower Eagle Ford wells and one Upper Eagle Ford well. The Dingo 03, which IP-ed at 1,424 BOE per day. This expands considerably the perspective fairway for Upper Eagle Ford across our acreage and gives us a high degree of confidence in our 80% number that we mentioned earlier. On Page 11, this is a summary of our most recent Lower Eagle Ford well results also very strong across our acreage. I’d like to point out the other two Dingo wells, both of which IP-ed in excess of 2,100 BOE per day. So whether we’re talking about Upper or Lower Eagle Ford, we demonstrated strong IPs across our leasehold, but IPs don’t tell the whole story. Slide 12 illustrates how our well results have continued to improve over time. This is the average gross well head converted production versus time vintaged by year of completion. When we started developing our acreage in 2011, our average well produced its first 100 MBOE back two and a quarter years. We took a step back which was in 2012 that rebounded in 2013 as we transitioned the zipper fracs reaching a tune of 100 MBOE in less than a year. We continue to improve on that in 2014 as you can see our average well cumulative production outpacing the 2013. On the Page 13, talking about well cost reductions, on average, we’ve lowered our AFEs by approximately $920,000, which primarily reflects the reduced completion cost associated with lower stimulation cost and our latest completion design. We expect this trend to continue as we already see our most recent chemical cost for stimulation continuing to decline below current AFE. We expect that decline of chemical prices to carry through on our drilling fluids too as well as production chemicals for LOE. None of these most recent chemical cost reductions are incorporated into our current AFEs. On the drilling side, we’ve also changed our design to be more cost effective. On our three-stream wells, we’re setting less surface casing, less intermediate casing, and drilling the intermediate hole section with water based mud. Combined with the retrofit of the pumps and their attendant ROP improvement, optimized well designs and continued improvement of pricing for drilling as well as completion services, we have a pretty clear pathway to the additional 12% to 14% cost reductions illustrated on this slide. For LOE, one of our largest single cost items has been salt water disposal or SWD, which is disposing of our produced water. We now have our own disposal facility and well up and running and capable of handling 20,000 barrels of water per day, which would cover most of our current water production. Currently, however, less than 20% of our total water production is currently pipelined in the disposal system with additional expansion underway, even without a complete water pipeline system we can truck water to our own facility, instead of taking it to commercial third-party sites. So this facility should continue to drive down one of our largest LOE line item. The next three pages are the three type curve that we are currently using. Page 14 is our Gonzales County type curve, which has the vast majority of our total well count over the last four years. The purple cloud you see in the background is actual range of well results, the double squares are the average monthly rates of these well histories and the red line is our type curve projection which as you can see is a very good fit as we try to make sure our projections match our history. On Page 15 it’s the Shiner 6-Pack now, we had previously referred to it as Beer Quad we’ve added a couple of more units, but the actual area extends beyond six units in that area now. And the last type curve page on Page 16 is our Upper Eagle Ford type curve and you can note the shallow will decline if this is demonstrated, and one of the reasons we’re very excited about our performance in drilling results that we’ve had. At this time I’ll turn it over to our CFO, Steve Hartman for the financial portion of the call.

[Steve Hartman:]

Okay. Thanks John, and good morning everyone. In the financial section I’m going to spend our time focusing on the 2015 guidance and liquidity, our fourth quarter and full year financial result that are summarized in the press release starting on Page 2 for your review. But first I’d like to mention before moving into guidance that we did record a significant impairment in the fourth quarter of $668 million, and as we explained in the release the impairment is related to our legacy East Texas and Mid-Continent gas properties and is of course driven by low natural gas and NGL prices. The impairment takes their book values down to about $30 million each, so the DD&A rate from these fields in 2015 will be much lower than their previous rates. Now moving back to the slides on Slide 18 and starting with our capital allocation for 2015, we are planning to spend $285 million to $345 million, which will fund a three to four rig program for the year. This is a 60% mid-point drop in our capital spending compared to the $784 million we spent in 2014. We will be focused on high grading the drilling program, drilling our highest return prospects first, we are concentrating on development in the Upper Eagle Ford; Peach Creek and Rock Creek fields in Gonzales County and the Lower Eagle Ford in Lavaca County, mostly in and around the Shiner 6 Pack area. This should provide production growth of 17% to 29% pro forma for the sale of our Mississippi assets and a litigation related volume adjustment in the third quarter of 2014. We plan to invest $15 million to $20 million in land acquisition, which along with our drilling program should keep our undrilled acreage and location inventory flat year-over-year. We have discontinued the new ventures program and have no money allocated to exploration or lease acquisition in new plays. We will consider restarting this effort when prices improve. And finally, our capital will be mostly front-end loaded in the first half of the year, it’s taken some time to get down to a three rig program from the eight rigs we operated in late 2014, and we were operating 3 frac spreads in the first quarter as we caught up the completions originally scheduled for 2014 as John described. We are currently a 2 frac spreads and expect to be a 1 frac spread by the second quarter. On the next slide, Slide 19, we will show how we plan to fund the program. This is a waterfall chart summarizing the work we did in 2014 to strengthen the balance sheet. We began 2014 with $206 million outstanding on the revolver and $240 million of liquidity and ended the year with $35 million drawn on the revolver and $477 million of liquidity. We accomplished this by monetizing our natural gas and crude oil gathering systems in Eagle Ford, selling our Mississippi assets, increasing our borrowing base and completing our convertible preferred stock offering. With these financings we were able to fully fund our $477 million cash flow outspend in 2014, and still almost double our liquidity. We plan to fund our projected outspend of $150 million to $190 million with this liquidity. Moving on to Slide 20, we highlight our revolving credit facility balance projections and our debt maturity schedule. You can see where we improved the balance sheet in 2014 by paying down the revolver by $171 million by year-end, while still growing the borrowing base from $300 million at year-end 2012 to $500 million by year-end 2014. Our spring redetermination is coming up in May, and we expect that borrowing base will come down with the lower bank price deck, the $400 million we show is an estimate based on early conversations with the bank. The bank lowered its price deck about 30%, but we are estimating a 20% decrease in our borrowing base because of our hedge portfolio and the drilling that we did in the second half of 2014. You can see we expect the revolver to be drawn about $160 million at mid-year that reflects the higher spending and lower price deck in the first half of the year. We then expect a lower outspend in the second half of the year ending the year between $185 million and $225 million drawn. If we assume a flat redetermination in the fall, we would end the year with $175 million to $250 million of liquidity. We would like to keep at least $150 million of liquidity available to us, so we appear to be fully financed for 2015 at this point. Looking to the right side of the slide, you can see we have no long-term debt maturities coming up, our credit facility matures in September 2017, and the two publicly traded bonds mature in 2019 and 2020. On Slide 21, we provide more detail on our 2015 program. Our full guidance table is shown on Page [Audio Gap]. We expect our production to range between 8.7 million to 9.6 million barrels of oil equivalent which is 23,800 to 26,200 BOE per day. Like our capital [Audio Gap] the growth to be front end loaded with the strongest growth in the first quarter, less growth in the second quarter and relative flat to possibly slightly declining from our peak in the second half of the year. But with that said, we still expect production growth in our exit rate 2015 over 2014. That assumes three rigs running in the second half of the year, if we ramp up to a fourth rig this will provide us quarter-over-quarter production growth against throughout all 2015. In the operations released on February 18th we guided the first quarter production of 23,500 to 25,500 [ph] BOE per day. As Baird mentioned, we are on track for achieving this with preliminary January production coming in towards the top end of that guidance range at just above 25,000 BOE per day. We expect LOE to improve on a per barrel basis as we add production across the fixed cost base and decrease our variable cost specifically chemical cost, water disposal and compression. We expect our GPT cost will increase on a per unit basis as we bring more production online from the Eagle Ford, which tends to carry a higher gathering cost than the legacy gas assets and also as we bring on the Eagle Ford crude oil gathering system online in the second half of the year, which you may recall increases our realized oil price but offsets this with higher gathering cost. We expect production and ad valorem taxes to increase as a percentage of revenue because of the ramp in oil which carries higher tax rate. We expect recurring cash G&A to trend at about $10 million to $11 million per quarter. D&A expense looks a little odd. We had a spike in the fourth quarter since we charged depletion expense for East Texas and Mid-Continent at the old depletion rate but those areas will have a much lower depletion rate going forward. Adjusted EBITAX is expected to be $300 million to $340 million for the year. This assumes pricing close to the current strip for 2015 and includes our cash settlements from hedges of roughly $120 million. Our total debt is anticipated to be $1.26 billion to $1.3 billion at year end. This guidance would suggest that we'll be running close to our leverage covenant of 4.0 at the end of the year. We currently have leverage of 3.0 so we are not in any danger of breaking the covenant soon. If necessary, we will be proactive and look to restructure the total debt covenant probably in our spring redetermination to give us financial flexibility and full access to our borrowing base liquidity. Based on some early conversations with the banks, I do not have any concerns in getting this amendment done. Moving on then the last two slides detail our hedge program. On Slide 22, we show our hedge portfolio in relation to some of our peers. This is data compiled by Barclays in their fourth quarter 2014 earnings preview, dated February 10th. The green bars show the percentage of total production comprised of oil and NGLs, the red square show the percentage of total production hedged. We have 62% of our total production hedged off of close to 80% of total production provided by oil and NGLs. For oil alone, which really drives our margins we have 83% of our forecast production hedged at a weighted average price of $90.20, so we are very well protected for 2015. Specifically that breaks out to 13,000 barrels of oil per day hedged for the first half of '15 at a price of $90.48 and 11,000 barrels of oil per day hedged for the second half of '15 at $89.86, and this is shown on the next slide. On the left, we show our oil hedge profile by quarter. On the right, we show our undiscounted cash proceeds of various oil prices. At $55 to $60 oil, we would expect our hedge portfolio to generate $112 million to $124 million in cash proceeds. These proceeds include the impact of having sold some lower puts with the $70 strike price. If you are modeling our hedges, remember to back out the hedge protection below $70 on 6,000 barrels per day in the first half of '15 and 5,000 barrels per day in the second half of '15. Using the price deck we use for guidance, we would expect $120 million in cash proceeds in 2015 and this is included in our adjusted EBITDAX guidance. So we feel we are well hedged for 2015. And that concludes the financial section, Baird.

[Baird Whitehead:]

Alright. Thanks, Steve and John. Marcus, we're ready to go ahead and take some Q&A please.

[Operator:]

[Operator Instructions] Our first question comes from the line of Welles Fitzpatrick from Johnson Rice. Please proceed with your question.

[Welles Fitzpatrick:]

Good morning.

[Baird Whitehead:]

Hello, Welles.

[Welles Fitzpatrick:]

You guys have talked about the GORs and the Upper Eagle Ford plenty before but is it fair to assume that on this new 810 EUR it is – call it 85% oil in Peach Creek and 65% oil in the Shiner area for the uppers as well as lower?

[Baird Whitehead:]

The stuff we drilled down in Lavaca counties is the GORs tended to be anywhere from 5,000 to 10,000 foot per barrel. I think if memory serves me correct, we were figuring about 50% was oil, if I am not mistaken I think it was another 20% or 25% that were NGLs and the remainder was gas. But there tends to be less oil as you go to the Southeast and the Upper Eagle Ford and tends to be gassier. As we come back to the west, we don't have enough data. The couple wells that John mentioned are the single well, the Dingo. I'd say the GOR and the Dingo – probably the Dingo 03 is probably pretty representative of what we typically see of lower GORs in Gonzalez County. So, I guess, getting back to your question after thinking through this I think your summary is probably pretty right on.

[Welles Fitzpatrick:]

And then as far as how rating company and the banks are treating the Upper Eagle Ford what kind of credit are they giving you all for those wells. And how does that play into your capital allocation decisions if maybe given that they are not as old as some of the lowers you are not getting quite as full credit? And one more if – on the Shiner 611 EUR is that also what rating company use at the year-end reserve report?

[Baird Whitehead:]

To answer your first question we get very little credit from rating company for the Upper Eagle Ford at year-end just because it was their opinion because we had less wells considering when the process starts. It was their opinion that there was not enough proof that the upper and lower are separate. We have asked them to relook at it based on what they know today. We don't have a report back. It would be sort of an interim report. But from what I have been told, they have come around based on the information that we have provided and updated information that in fact they will take that into consideration and will strongly consider the upper and lower being separate reservoirs. As far as your other question, rating companies, PUD reserves and Shiner typically are less than ours and they use a different B factor, we use 1.2 they use 1.1. They use the terminal decline rate at 8%, we use a terminal decline rate of 5%. To remind everybody actually last year used terminal decline rate of 12%, so they've gone from 12% to 8%. So I think we consider that good, of course, if they are sort of heading our direction of 5%. So, there is a difference in PUD reserves between what we estimate and what they estimate. There is good reason for our numbers. They have reason for their numbers. And really I'll just leave it at that.

[Welles Fitzpatrick:]

Alright, that's perfect. Congrats on the quarter and great guidance.

[Baird Whitehead:]

Alright. Thank you, Welles.

[Operator:]

Our next question comes from the line of Neal Dingmann from SunTrust. Please proceed with your question.

[Neal Dingmann:]

Good morning, guys. I'd say John did a good job walking through some of the separate Eagle Ford. I guess, my question I just want to make sure. It appears to me after the first well or two, I guess, I should say on the recent wells, everything has been improving there. I'm just – what I am trying to reconcile I know there was some, I guess, maybe I'll call it confusion would you originally had that upper Marl slide out and I think you know again it showed over – I think the EUR there was 900 plus and then I know on your prior update you guys set an average of about 17,000 barrels and now most recently it looks like here with 22 stages around 810. Could you just talk around that, Baird, as far as kind of per stage or how you and John are thinking about the EURs of these Upper Eagle Fords today?

[Baird Whitehead:]

The bigger upper number we had that here is we only had a handful of wells primarily being in Welhausen areas and those are – Welhausen and Martinsen area and those outstanding wells. There are still 900,000 or 1 million barrels, in fact, if I am not mistaken the Martinsen I think is north of 1 million barrels. As we drilled more wells not every well was as good as Welhausen/Martinsen, so we – as far as an average standpoint we have brought that 900,000 plus number down to more reflect what we think we can drill going forward across our entire acreage position since – now there is just a lot more of a fairway that we think that we can drill. But in any case that's sort of the evolution of how we got to where we are. We don't necessarily think on a per stage basis. I realize there is technical reason to do that, but most of our wells now are probably in the 5,500 to 6,000 foot range, John, correct?

[John Brooks:]

Correct.

[Baird Whitehead:]

So we are talking about the 22.5 to 23 frac stages. Now going forward and since we have lengthened our frac stage from 225 to 250, we don't think that's going to have any difference in our per frac stage contribution. So that's sort of how we got to where we are. I don't know if it is 800 or 770 or 830 as we drill more wells over time. I think we'll continue to hone in on a better number across our acreage position, but that's sort of the evolution of how we got to where we are right now.

[Neal Dingmann:]

That makes sense. And then just looking at that Slide 4 where you guys – and you touched on this, Baird, where you were talking about earlier the fourth quarter production variance. It sounds like that for you and John that that some of those mechanical issues related shut-ins are certainly not seen that in the current quarter and don't expect anything like that. Is that the case?

[Baird Whitehead:]

Well, we’re trying to taking into account in our guidance and how we estimate production but just because of the sheer amount of activity we had in the Welhausen area just ended up being more than we had originally thought. I would expect is because we’re running only three rigs, of course, this should be a much less of a problem going forward, but we still will have some we think we had put adequate cushion within our guidance projection for 2015 to air on this side are being conservative as far as effective shut-in. So we are think we are in good shape.

[Neal Dingmann:]

Okay. And then lastly, Baird, for your or Steve just wondering how do you look at obviously we're still in pretty tough macro-environment with the headwinds but you all have some decent hedges out there. How do you guys look at? I'm just kind of wondering would that the – the slight outspend that you do have if prices fell another 10%, 20% is there sort of a number that you feel comfortable with an outspend or is it more on sort of the debt level that Steve walked through. How do you guys sort of think about that as far as activity and outspend going forward?

[Steve Hartman:]

I'd say that it is driven mostly by liquidity. I don't think that the leverage is going to be an issue because as I mentioned in my discussion that I think we're going to get that taking care of the amendment in the spring. So we are really focusing on the liquidity. Our hedge program has us 83% hedged and that's pretty much at the limit that we are allowed to hedge for the credit facility. So we really can't hedge anymore with the three rig program in 2015. We're really not all that sensitive to changes in oil prices at this point. So, that's what we're going to be keeping eye on as liquidity.

[Neal Dingmann:]

That helps. Thanks, Steve. Thank you all.

[Baird Whitehead:]

Thank you.

[Operator:]

Our next question comes from the line of Steve Berman from Canaccord. Please proceed with your question.

[Steve Berman:]

Thanks. Good morning. Expanding on Neal's last question. Can you talk about 2016 hedging? I mean, are you adding these kind of prices or would you be looking for something higher before you add to that 4,000 barrels of oil a day?

[Steve Hartman:]

We are probably waiting for a little bit higher pricing. There is some nice contango in the curve, so we are watching it. But at this point there is no real reason to rush out. 4,000 is a good base, especially when we are about $88 as weighted average floor they are all swaps. So it is all just – that's the swap rise. So I'd say that we are probably going to be patient.

[Steve Berman:]

And Steve while I got you. The 1.4 billion PV10 at year end '14 was based on $95 oil and 4.35 [ph] gas, do you have that number at the strip? What that 1.4 billion would be calculated at the strip?

[Steve Hartman:]

I don't – Jim is saying that we'll look it up and we'll give you a call back, but I don't have that number…

[Baird Whitehead:]

I mean, the only thing we have that 3 billion we have for these kind of estimates is on 3P that was running at 60 flat, and I think 4. I realize not broken down by reserve component, but it is sort of pushing in perspective of the higher oil priced used for approved versus what we have 3P.

[Steve Berman:]

And last one from me. Given your success with the Upper Eagle Ford what would it take to change the allocation of I think you have 42% of your drilling and completion CapEx allocated to the Upper Eagle Ford, but what would it take for that number to go up and lower go down at this point. What would you need to see?

[Baird Whitehead:]

I think if we saw some outstanding wells we are surprised it is in the Upper that we don't want to immediately try to offset. I think that would certainly have a bearing on us moving some money around. But based on what we plan on drilling the Gonzales county that being Peach Creek and Rock Creek, we had some excellent remaining opportunities up in that area and of course returns are – is high as we have because of the lesser cost those being two string kind of wells. But we always have a flexibility of moving money around and I think at this time we'd wait and see and see how we do on some of these newer wells. And if necessary move some money around.

[Steve Berman:]

Thanks, Baird. Thanks, Steve.

[Baird Whitehead:]

Alright. Thanks, Steve.

[Operator:]

[Operator Instructions] Our next question comes from the line of Kim Pacanovsky from Imperial Capital. Please proceed with your question.

[Kim Pacanovsky:]

Good morning, everyone. On the Upper Eagle Ford, obviously, it is positive that Wright brought that terminal decline number down. I'm sorry that was on the lower Eagle Ford? On the upper Eagle Ford, do you think that they would starting at a super conservative number again and then ratcheting it down or do you anticipate that they will look at the two zones more equally?

[Baird Whitehead:]

I think it is going to take some time for them to come to our, what we think at this point of time. They are using a type curve that is pretty similar for the upper as they use for the lower. As you can see on the type curve that John showed for the upper. The one good thing about the upper because they tend to clean up over a longer period of time and they have a flatter initial decline. So that's a positive from our perspective, Wright has not built that into their type curve at this time. So I think it's going to take some more information for them to go in that direction. But I think they will go in that direction over time.

[Kim Pacanovsky:]

And then if they had considered the upper and the lower as distinct zones in your recent engineering report. What kind of additional PUDs do you think you would have been able to book? Just based on are there going to be reserve numbers, but just based on locations?

[Steve Hartman:]

I don't have that information handy. I'd even hate to take a wild guess at this time.

[John Brooks:]

It still be constrained by the SEC five year rules.

[Steve Hartman:]

Yeah, not only five year by which you can direct offsets, of course. I don't know the answer to that question, Kim, sorry.

[Kim Pacanovsky:]

Okay. And can you just give us some color on the 8 million of downward revisions in the Eagle Ford?

[Baird Whitehead:]

Well, a lot of it was because of rating companies PUD type curve. Again they changed their type curve which we feel was pretty conservative, but I can't control that. We feel that it was too much of a cut, but it is what it is. And again we think over time we will come back around because if you lay our PUD type curve and their PUD type curve on top of one another they don't really start to diverge until after 36 months. That's because of the B factor in as you go out longer probably get to year five or six as where you get to the 8% versus our 5% which is beyond 10 years. So there is couple of things going on. We think over time – time seriously is a problem, of course, but it is what it is and we still feel confident with our internal numbers.

[Kim Pacanovsky:]

Okay. And then last question. Just looking at your guidance for revenue and EBITDA, just because the – you know, when you talk about your hedges, you talk about the 80% to 90% being hedged at $90 and that’s not including the short-puts, which I think is kind of misleading, but when you have your revenue guidance and your EBITDA guidance are those short-puts included?

[Steve Hartman:]

Yes, Kim they are definitely included.

[Kim Pacanovsky:]

Okay.

[Steve Hartman:]

We still receive a significant amount of money from the hedge program even with the lower puts in place, we still get the maximum $20 to $25 for each one of those trades, so it’s a significant amount of money compared to what we – when we start floating it below $70 on that 5,000 and 6,000 barrels a day that I mentioned. When we’re below $70, effectively we’re about 40% hedged on that incremental – below $70.

[Kim Pacanovsky:]

All right, okay. Thanks a lot.

[Baird Whitehead:]

All right. Thank you.

[Operator:]

Our next question comes from the line of Sean Sneeden from Oppenheimer. Your line is now open.

[Baird Whitehead:]

Hi, Sean.

[Sean Sneeden:]

Good morning. Baird or John, maybe for you. But just kind of giving how your CapEx is front-end loaded this year. Can you maybe talk about how what you’re thinking your PDP base decline progresses throughout the year? For instances, you’re generally modeling improving from by year-end from kind of the 40% to 45% that we kind of saw at the end of the fourth quarter here?

[Baird Whitehead:]

Well, we’ll have most of our production growth in the first and second quarter as we work off the drilling inventory that we had at year-end because of the eight-rigs. After you get beyond the second quarter it takes a step down somewhat within or sort of flattish between the third and the fourth quarter. I would estimate that we could probably keep production fairly flat with around 3.5 rigs going forward beyond 2015 as a rough estimate, if that helps you.

[Sean Sneeden:]

Okay. That’s helpful.

[Baird Whitehead:]

Okay.

[Sean Sneeden:]

Then Steve, maybe on liquidity. Thank you for all the detail on the borrowing base assumption. I’m just kind of curious, how are you guys thinking about that fall redetermination, looks like you’re thinking that you’d be roughly flat, is that been driven by what you think you’ll find in terms of reserve adds and your hedge book or maybe any color around that would be helpful?

[Steve Hartman:]

Yeah, I think it’s the latter. It’s obviously very difficult to tell at this point what’s going to happen, we have no idea what pricing is going to be at that point, but we are converting a lot of our PUD locations where we don’t get a lot of value from the banks and the redetermination in the borrowing base in the PDP and we’re keeping that flat, and more specifically we’re drilling a lot of the Upper Eagle Ford, which has a flatter decline, so has more value in the borrowing base. So we just feel it’s a reasonable estimate to go with at this point.

[Sean Sneeden:]

That’s fair enough. You know I guess, kind of, with that being said, how are you guys thinking about – I think you’re pretty well funded for this year, but how are you thinking about planning for next year, just kind of giving from borrowing base in the hedge book? Are you guys kind of thinking about larger and strategic transactions, before you might bring in a partner, or maybe you can talk about how you think about the longer term funding plan?

[Steve Hartman:]

Well, a lot of is going to be product price driven, I mean it depends on how loan prices are in this range, but I mean we have other alternatives, some of which you mentioned, this was a longer term kind of issue, some speculated at this time exactly what we would do, but we have a number of options, including sell off assets, bringing a partner in as you mentioned, whatever the case may be.

[Sean Sneeden:]

Do you think also then by – call it or your mid-year, you have a better sense of kind of what the plan for 2016 will be?

[Steve Hartman:]

I do, I mean, we’re keeping our eye opened and start working on things as far as what we need to do as the year progresses, so as in 2016 we have sufficient liquidity to continue our program. So, we’ll start on trying to figure out exactly what we need to do and get it done second half of the year.

[Sean Sneeden:]

Okay, that’s helpful. Thank you.

[Operator:]

Our next question comes from the line of Gail Nicholson from KLR Group. Please proceed.

[Baird Whitehead:]

Hi, Gail.

[Gail Nicholson:]

Hi, good morning. I’m just kind of looking at the Upper Eagle Ford well that are being drilled in 2015, are those going to be concentrated more in the Welhausen and Martinsen area? Are they going to be all over the acreage position?

[Baird Whitehead:]

They’re going to spread through our acreage position based on the additional wells that we have drilled in the second half of last year. So yes, it will be more spread apart than just drilling in the Welhausen area.

[Gail Nicholson:]

Okay. But nothing on that – the acreage that was acquired in Eastern Lavaca?

[Baird Whitehead:]

We – I think, John, help me out here. I think we have one well drilled – we already have drilled one well.

[John Brooks:]

Correct.

[Baird Whitehead:]

We have not yet completed it, if I’m not mistaken.

[John Brooks:]

Production is catching on it right now.

[Baird Whitehead:]

Okay, so answer to your question. We’ve already drilled one well in that acquired acreage.

[Gail Nicholson:]

Okay, great. Then just, you mentioned the potential of maybe you ramping up to four rigs in the later part of 2015, what type of macro environment and/or further well cost reductions do you guys need to see in order to accelerate that drilling?

[Baird Whitehead:]

Well, we want to get comfortable that oil prices are going to stand at a level that we think make a lot of sense, you know, make a lot of sense. First thing I think we’d like to see nudged closer to 70 – 65 to 70, but at this point in time, if we could drive our well cost down the 10% to 15% we were talking about, I still think we’d stick with the three rigs and just have fiscal prudency and making sure that we go into 2016 in good shape would be my opinion right now. It would be – it would take a strengthening oil price to get excited to add – to one add another rig as the year progresses.

[Gail Nicholson:]

Okay, great. And then just looking at the decline rate in the Upper Eagle Ford, are you guys seeing any difference in the gas and oil volume declining? Are they declining at similar rate as [for rest of] the time?

[John Brooks:]

The GOR is standing relatively constant, so they’re declining at the same rate.

[Gail Nicholson:]

Okay, great. Thank you.

[Baird Whitehead:]

All right. Thank you.

[Operator:]

Our next question comes from the line of Scott Hanold from RBC Capital Markets. Please proceed with your question.

[Baird Whitehead:]

Hey Scott.

[Scott Hanold:]

Hey thanks, thanks for taking my question here, and good morning. Couple of questions here and maybe the first just on your Upper Eagle Ford again, when you step back and look at where you’re spying locations for 2015, can you give us a sense of how much of that do you think is going to be more testing some of your acreage versus high level of confidence. So when you step back and look at the range of EUR as you’ve provided for the Upper Eagle Ford, where on that scale would you kind of point us to in terms of your confidence with your drilling?

[Baird Whitehead:]

It would be in a higher category. I think at this time, based on our drilling program, the second half of the year and especially with this well we just drilled up in Gonzales, and Lavaca, and Fayette County sort of come together, it gives us a lot of confidence. This thing is bigger than we originally thought it was. So I think we have a high degree of confidence right now, there is always caveats to that, but I think we have a high degree of confidence in this Upper Eagle Ford drilling program in 2015.

[Scott Hanold:]

And so when you look at the 2015 program, in terms of where those well spuds are, is there a little bit more I guess development versus exploration of the Upper Eagle Ford?

[Baird Whitehead:]

That’s correct.

[Scott Hanold:]

Okay, okay. And then one more question on sort of I guess future funding potential divestitures. When you step back and look at the Eagle Ford and the Upper Eagle Ford that you all have, that’s a lot to do for a company of your size, strategically does that make sense for you all to be in the kind of Cotton Valley/ Haynesville player in the mid-Con region, I mean, would those be the first areas you'd like to shut-off and become a pureplay, Eagle Ford player or would it be – would you have an appetite of just partnering with somebody in your Eagle Ford program?

[Baird Whitehead:]

Well, it’s my opinion right now that I would not ideally like to dilute our interest in the Eagle Ford. I think we're going to be one trick pony rather than one trick pony in the Eagle Ford right now based on results and based on we do have a fairly significant gas component in spite that they are oil well. So it’s not that we eliminated our exposure to natural gas by standing in Eagle Ford by ourselves. So answering your question, yeah clearly the East Texas stuff, since we really haven’t spent any money there since roughly 2010, would be an asset considering there is interest in those kind of assets right now, especially with some of the Cotton Valley’s horizontal drilling going on and some of the Haynesville even in today’s gas prices because the costs have come way down. So it’s just has to compete with what we have in the Eagle Ford at this time, but it’s certainly an asset that we would consider selling yes.

[Scott Hanold:]

Okay. That’s great. Thanks guys.

[Baird Whitehead:]

Thanks, Scott.

[Operator:]

Due to time constraints our final question comes from the line of Adam Michael from Miller Tabak. Please proceed.

[Adam Michael:]

Hi, I just wanted to ask a question, I don’t think I’ve heard it yet. I assume that the – there was a Wall Street Journal article this morning about the company being for sale, if that was not true that you had probably clarify that in your opening remarks. Can you just comment on the story, just to set the record straight?

[Baird Whitehead:]

No, I’m not going to comment. Look it’s our policy not to comment on these matters.

[Adam Michael:]

Okay, fair enough. And then just one follow-up question on the Upper Eagle Ford. As far as spacing goes, have you seen any kind of communication between the wells that were drilled on the same pads, or does the spacing look similar to kind of what you expect to see I guess in the Lower Eagle Ford?

[Baird Whitehead:]

Yeah, I think we think the spacing at this time would be the same what we would expect in Lower Eagle Ford, so the 400 foot criteria we think is a correct spacing on the Upper.

[Adam Michael:]

And then in regards to your 80% of your acreage that you think as perspective for the Upper Eagle Ford, was that something that there was like a certain thickness, that was kind of a cut off or 80% met that thickness or what’s kind of the – I guess the reasoning behind that 80% number?

[Baird Whitehead:]

There is [indiscernible] reasons, there are thickness reasons as you say, stated, there is also result driven reasons based on the second half of 2014 program in the Upper, so a combination is to flush this Dingo well that we keep talking about up in where Lavacan and Gonzales and Fayette come together really as – has been an eye opener as far as expectations in the Upper, so that’s the reason. And we’ve just got more data.

[Adam Michael:]

Okay. Thanks for taking my questions guys. That’s it from me.

[Baird Whitehead:]

All right. Thank you.

[Operator:]

I would now like to turn the call over to our speakers for closing remarks.

[Baird Whitehead:]

All right. Thank you very much. And we thank you for listening in. There is lot of question as this is a challenging environment, but we think we’ve made some major changes to our activity level in a virtue period of time with our number one goal to protect liquidity of course. But we’re going to ride at this well, but the most important thing to remember as an investor is we still have a great asset, which gives us a lot of flexibility in running room once the prices rebound. And we look forward to our May conference call, and thank you very much.

[Operator:]

Ladies and gentlemen, thank you for attending today’s conference call. This does conclude today’s program. You may all disconnect. Have a wonderful day.