Ranger Oil Corp (ROCC) 2014 Q4 法說會逐字稿

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'll 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.

All right. Thank you very much, Marcus. And thank you for joining us today for Penn Virginia's fourth-quarter and year-end 2014 conference call. As always, I'm joined today by members of our Management team, which include 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 the K, which we filed last night. We changed our call up a little bit this time. There's actually a presentation out there on the web that we will go through simultaneous to the call. First slide, I'm 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 the significant completion inventory during the fourth quarter is beginning to provide production growth we had expected. And now you are starting to see that sharply higher total Company production in January of 25,200 barrels equivalent per day, with all of 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 Eagle Ford of over a billion barrels equivalent, which is about a 260% increase from last year with an associated PV-10 of about $3 billion. We also ended the year with Eagle Ford proved reserves of 94 million barrels equivalent, which is 24% higher than last year and has a PV-10 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 the dedicated effort of testing and understanding the potential of the Upper Eagle Ford, we feel that we now have successfully derisked this new play type with a total of 20 wells drilled and completed to date with excellent averaged 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 a 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 for the 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 focus on drilling our highest return of wells in this lower cost environment.

Our overall production growth associated with the 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 for the third quarter we have from our Mid-Continent assets, we except that pro forma growth to be 17% to 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, fourth-quarter product revenues were $112 million, or $57.03 per barrel equivalent. We're also making progress in reducing our production costs, 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, for a decrease of about $1.80 per barrel equivalent.

The initial potential rates that the Eagle Ford wells completed since the third quarter averaged 1,226 barrels equivalents per day, with a corresponded 30-day rate for the appropriate wells of 937 barrels equivalent per day. The recent average activity 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 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 perspective in the play with over 1,800 Upper Eagle Ford locations by itself.

The next slide attempts to explain a variance that we had in our fourth quarter production as compared to [guidance]. I know there was a meaningful shortfall, but mostly it was associated with the large inventory of completions we had due to the active drilling program that we had at the time with eight rigs drilling. Candidly, delays and additional off-set 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 during frac operations itself, we had to shut some of the previously completed wells in. The other category of mechanical issues was about a 1,000 barrels a day and was primarily associated with two Hinze wells and one Netardus well. Those operational issues were ultimately resolved, but they did slow things down somewhat or restrict production for a period of time.

One point that is important to mention, that there's 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 expect, some wells that 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 purpose, also shown is what we have provided for the first-quarter production guidance. And at this time, we are confident that our first-quarter production will be within that range.

This next slide gives a lot of detail concerning what we hope to get accomplished and our strategy in 2015. Most importantly is to preserve financial liquidity and our Eagle Ford acres 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 price decks. But even taking that into account, along with the anticipated 2015 high spend of $150 million to $190 million, we expect and will take steps if necessary to remain below our 4 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. $1 of lease acquisition capital goes a lot further today than what it did at this time last year since acreage costs 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%, and 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 a flat $65 per barrel oil price, the Shiner Beer Quad area of almost 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 lease operating expenses further as the year progresses. These additional cost reductions have not been built into our current budget or guidance, so we review any benefits of those as potential upsides as the year progresses. John will get into a little bit more detail as how we expect to accomplish that as the year moves along. But if we can be successful in getting our well costs down an 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 re-increase to 40%.

One issue that I want to expand upon, because I think there's some confusion, is our drilling and completion costs include almost $500,000 for surface facilities. That's for tank, batteries, your high pressure, low pressure separator, heater treaters, things of that nature, not all of your peers include these facility costs in what they report for drilling and completion costs. And it's just something you need to be aware of since these surface facility costs are a significant percentage of our reported drilling and completion costs.

The next slide I'm not going to spend a lot time on, but the slide tells a good story all by itself. With a 60% decrease in tentative 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, or 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, which now takes 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/or 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 that location inventory from 1,900 locations to 3,400 locations, which, of course, provides a significant number of years of drilling inventory especially with the reduced rig count.

As in the past, which lends credibility, all 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 a reduction in drilling activity with an approximately 50% of our acreage HBP'd in the Eagle Ford, we need to have a plan on how we're 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 a lease-extension provisions that we have on our lease. So between our drilling program and any renewal money, which will be small at roughly $1,500 per acre, we don't have a problem in 2015.

And with that, I'd like to go ahead and turn the call over to John Brooks to give you some operational detail.

Thanks, Baird. I'm going flip over to page 9, which starts the fourth-quarter 2014 operations summary. We finished up 2014 meeting our goal of reaching the 100,000 net acres milestone, actually exceeding that by a couple of thousand acres. It's a highly contiguous position that has been substantially derisked through the drill bit. And with our ongoing success in the Upper Eagle Ford, as Baird says, we now have a drilling inventory in excess of 3,400 total Eagle Ford locations, assuming full development of the assets stacked-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 our eight-rig program generated. A lot of that completion inventory has been worked off as evidenced by January 2015 production of almost 22,000 BOE per day, which is an 18% increase over December. Also in 2014, we were targeting 400,000 pounds of proppant over 225-foot stage links. This significant increase in proppant required longer pump times, resulting in fewer stages per day, and lengthened our cycle times.

Company-wide 2014 oil production growth was 35%. And we expect 2015 total-Company production growth of 10% to 20%, pro forma 17% to 29%. And 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 prospective across about 80% of our leasehold with approximately 1,850 locations.

Our drilling department continues to improve over all 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 wells in the prior year. This was 1.737 million feet, an 81% increase year-over-year. We are now operating three 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 2-string well was drilled in 8.85 days, from spud to rig release. And our quickest 3-string well was drilled in 15.73 days from spud to rig release. Our average 2-string well was drilled in 16.1 days, and our average 3-string well was drilled in 25.8 days from spud to rig release. Another change we've implemented is in our well design. Previously, our 3-string 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 in the ground.

These bigger hole well designs had their own learning curve, since we have sparse relevant fit 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 bit records, our ROPs continue to improve, and it looks like most of the learning curve may be behind us. The larger hole size allows for larger directional tools, which have longer running life at the higher temperatures associated with the deeper wells in the 3-string areas. This keeps us on bottom drilling more and tripping for tools less. Besides improving mechanical reliability, one of the advantages of the bigger hole is lowering treating 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 pounds to 350,000 pounds per stage for 250-foot state length, or 1,200 pounds to 1,400 pounds per foot of lateral. Currently, our stimulation costs are running around $100,000 per stage for a 300,000-pound stage. We expect this to decline further as all our stimulation costs, 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 proppant usually correlates to improved production response, we had several instances where the additional proppant loading did not result in materially improved production. So while it's still early, in some instances it appears we may have reached the point of diminishing returns with regards to proppant loading. This observation helped guide our latest completion design with somewhat less proppant per foot. We'll continue to optimize our completion design and selectively pump higher proppant loading where it makes the most sense. With regards to LOE, we're also continuing to reduce that LOE as illustrated in the graph at lower right of 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, it's 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 at 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 3, which IP'ed at 1,424 BOE per day. This expands considerably the prospective 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 talk about Upper or Lower Eagle Ford, we've demonstrated strong IPs across our leasehold. But IPs don't tell the whole story.

Slide 12 illustrates how our wells results have continued to improve over time. This is average gross well head cumulative production versus time, vintaged by year of completion. When we started developing our acreage in 2011, our average well produced its first 100 MBOE in about 2.25 years. We took a step backwards in 2012 but rebounded in 2013, as we transitioned to zipper fracs, reaching a cume of 100 MBOE in less than a year. We continued to improve on that in 2014, as you can see our average well cumulative production out pacing 2013.

On to page 13, talking about well cost reductions. On average, we've lowered our AFEs by approximately $920,000, which primarily reflects the reduced completion costs associated with lower stimulation costs and our latest completion design. We expect this trend to continue as we already see our most recent chemical costs for stimulation continuing to decline below current AFE. We expect that decline in 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 changed our design to be more cost effective. On our 3-string wells, we're setting less surface casing, less intermediate casing, and drilling the intermediate whole section with water based mud. Combined with the retrofit of the pumps and their attended ROP improvements, 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 handing 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 to disposal system, with additional expansion under way. 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 items.

The next three pages are the three type curves that we are currently using. On 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 yellow squares are the average monthly rates of these well histories. In 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 Six Pack now. We had previously referred to it as the Beer Quad. We've added a couple 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. You can note the shallower decline that this has demonstrated and one of the reasons we're very excited about our Upper Eagle Ford performance and 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.

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 results are summarized in the press release starting on page 2 for your review.

But first, I'd like to mention before moving in to 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 $295 million to $345 million, which will fund a three to four rig program for the year. This is a 60% midpoint drop in our capital spending compared to the $794 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 Six 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 third-quarter 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 three frac spreads in the first quarter as we caught up to completions originally scheduled for 2014, as John described. We are currently at two frac spreads and expect to be at one 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 a convertible preferred stock offering. With these financings, we were able to fully fund our $477 million cash flow out spend in 2014 and still almost double our liquidity. We plan to fund our projected out spend 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 the 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 midyear. 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 in liquidity. We would like to keep at least $150 million in 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 [7] of the earnings release. We expect our production to range between 8.7 million and 9.6 million barrels of oil equivalent, which is 23,800 to 26,200 BOE per day. Like our capital program, we expect the growth to be front-end loaded, with the strongest growth in the first quarter, less growth in the second quarter, and relatively flat to possibly slightly declining from our peak in the second half of the year. 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 would provide us quarter-over-quarter production growth again throughout all of 2015.

In the operations release on February 18, we guided to first quarter production of 23,500 to 23,500 BOE (sic -- per press release "25,500") per day. As Baird mentioned, we are on track for achieving this with preliminary January production coming in toward 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 costs 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 a higher gathering cost. We expect production and ad valorem taxes to increase as a percentage of revenue because of ramp in oil, which carries a higher tax rate. We expect recurring cash G&A to trend at about $10 million to $11 million a 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 EBITDAX 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 leverage covenant of 4 at the end of the year. We currently have leverage of 3, so we are not in any danger of breaching 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, the last two slides detail our hedge program. On slide 22, we show our hedged portfolio in relation to some of our peers. This is data compiled by Barclays in their fourth-quarter 2014 earnings preview dated February 10. The green bars show the percent of total production comprised of oil and NGLs. The red squares 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 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 2015 at a price of $90.48, and 11,000 barrels of oil per day hedged for the second half of 2015 at $89.86.

And this is shown on the next slide. On the left, we show our oil hedged profile by quarter. On the right, we show our undiscounted cash proceeds at various oil prices. At $55 to $60 oil, we would expect our hedged portfolio to generate $112 million to $124 million in cash proceeds. These proceeds include the impact of having sold some lower puts with a $70 strike price. If you're modeling our hedges, remember to back out the hedge protection below $70 on 6,000 barrels per day in the first half of 2015, and 5,000 barrels per day in the second half of 2015. 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?

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

(Operator Instructions)

Welles Fitzpatrick, Johnson Rice.

Good morning.

Hello, Welles.

On the -- you guys have talked about the GORs in the upper Eagle Ford plenty before. But is it fair to assume that on those new 810 EURs, it's, call it, 85% oil in Peach creek and 65% oil in the Shiner area for the uppers as well as the lower?

The stuff we drill down in Lavaca county, 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'm not mistaken, I think there was another 20% or 25% that weren't 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 it tends to be gassier. As we come back to the west, we don't have enough data.

The couple wells that John mentioned, or the single well, the dingo. I'd say the GOR on the dingo, probably the dingo 3, is probably pretty representative of what we typically see of lower GORs in Gonzales county. So getting back to your question, after thinking through this, I think you're summary is probably pretty right on.

All right, perfect. And then, a far as how Wright and 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 given that they're not as old as some of the lowers, you're not getting quite as full credit? And one more, on the Shiner, 611 EUR, is that also what Wright and company used at the year-end reserve report?

To answer your first question, we got very little credit from Wright and 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 re-look at it based on what they know today. We don't have a report back that would be an interim report. But from what I have been told, they have come around based on the information we that 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, Wright and Company's PUD reserves in Shiner typically are less than ours. And they use a different B factor, we use 1.2; they use 1.1. They use a terminal decline rate at 8%; we use a terminal decline rate of 5%.

To remind everybody, actually last year, they used a terminal decline rate of 12%, so they've gone from 12% to 8%. So I think we consider that good, of course, that they're heading our direction of 5%. So there is a difference in PUD reserves between what we estimate and what they estimate.

There's good reason for our numbers. They have reason for their numbers. And really I'll just leave it at that.

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

All right, thank you, Welles.

Neal Dingmann, SunTrust.

Good morning, guys. Baird, you and John did a good job walking through some of this upper Eagle Ford. 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. What I'm trying to reconcile, I know there was some, maybe I would call it confusion.

When you originally had that upper Marl slide-out, and I think, again, it showed over -- I think the EUR there was 900,000 plus, and then I know on your prior update, you guys had an average of about 717,000 barrels. And now, most recently, it looks like here with 22 stages, around 810. Could you just talk around that, Baird, as far as per stage, or how you and John are thinking about the EURs of these upper Eagle Fords today?

The bigger upper number we had out there is when we only had a handful of wells, primarily being the Welhausen areas, the Welhausen and the Martinsen areas. And those are outstanding wells. They're still 900,000 to 1 million barrels.

In fact, if I'm not mistaken in Martinsen, I think it's north of a million barrels. As we've drilled more wells, not every well was as good as the Welhausen/Martinsen. So 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's 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's technical reason to do that, but most of our wells now are probably in the 5,500- to 6,000-foot range, John, correct?

Correct.

So we're talking about 22.5, 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's 800, or 770, or 830. As we get 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.

No, that makes sense. And then, just looking at that slide 4, and you touched on this Baird, where you were talking about earlier the fourth-quarter production variance. It sounds like, after listening to you and John, that some of those mechanical issues, related shut-ins, you're certainly not seeing that in the current quarter and don't expect anything like that. Is that the case?

Well, we try to take it 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, it just ended up being more than we had originally thought.

You know, I would expect it becomes, with running only three rigs, of course, it should be a much lesser of a problem going forward. But we still will have some.

We think we have put adequate cushion within our guidance projection for 2015 to err on the side of being conservative as far as the effect of shut-ins. So we think we're in good shape.

Okay, and then lastly, Baird, for you or Steve, just wondering how do you look at -- obviously, we're still in pretty tough macro environment with the headwind, but you all have some decent hedges out there. How do you guys look at, I'm just wondering would the slight outspend that you do have, if prices fell another 10%, 20%, is there a number that you feel comfortable with an outspend?

Or is it more on the debt level that Steve walked through? How do you guys think about that, as far as activity and outspend going forward?

Yes, Neal, I'd say that it's driven mostly by liquidity. I don't think that the leverage is going to be an issue. Because as I mentioned in my discussion, I think we're going to get that taken care of with an amendment in the spring.

We've really focused in on the liquidity. Our hedge program has us 83% hedged, and that's pretty much at the limit that we're allowed to hedge per the credit facility. So we really can't hedge anymore with a three-rig program in 2015.

So we're really not all the that sensitive to changes in oil prices at this point. That's what we're going to be keeping our eye on is the liquidity.

That helps. Thanks, Steve. Thanks, you all.

All right, thank you.

Steve Berman, Cannaccord.

Hi, Steve.

Thanks, good morning. Expanding on Neil's last question, can you talk about 2016 hedging? Are you adding at these kind of prices or would you be looking for something higher before you add to that 4,000 barrels of oil a day?

We're probably waiting for a little bit higher pricing. There is some nice contango in the curve, so we're watching it. But at this point, there's no real reason to rush out.

4,000 is a good base, especially when we're about $88 as a weighted average floor. They're all swaps, so that's the swap price. So I'd say that we're probably going to be patient.

Okay. And Steve, while I got you, the $1.4 billion PV-10 at year-end 2014 was based on $95 oil and $4.35 gas, do you have that number, the strip? What that $1.4 billion would be calculated at the strip?

I don't know, Steve, sorry. Jim is saying that we'll look it up, and we'll give you a call back, but I don't have that number.

The only thing we have that, $3 billion we have for the internal estimates on 3P, that was run at a 60 flat, and I think four. I realize it's not broken drown by a reserve component, but it's sort of puts it in perspective of the higher oil price used for proved versus what we have for 3P.

And last one for me, given your success with the upper Eagle Ford, what would it take to change the allocation? 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 the lower go down at this point? What would you need to see?

I think if we saw some outstanding wells that were surprises in the upper that we wouldn't want 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 in Gonzales county, that being Peach creek and Rock creek, we have some excellent remaining opportunities up in that area.

And, of course, returns are as high as we have because of the lesser costs, 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 be a wait and see and see how we do on some of these newer wells. And if necessary, move some money around.

Thanks Baird; thanks Steve.

All right, thanks, Steve.

(Operator Instructions)

Kim Pacanovsky, Imperial Capital.

Yes, hey, good morning, everyone. On the upper Eagle Ford, obviously, it's positive that Wright brought that terminal decline number down. I'm sorry, that was on the lower Eagle Ford.

On upper Eagle Ford, do you think that they would be starting at a super conservative number again and ratcheting it down? Or do you anticipate that they will look at the two zones more equally?

I think it's 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's 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. And Wright has not built that in to their type curve 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.

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 -- you don't have to give me reserve numbers -- but just based on locations.

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

It would still be constrained by the SEC five-year rule.

Well, not only five year, but which you can direct [off-set] of course. So I don't know the answer to that question, Kim. I'm sorry.

Okay, and can you just give us some color on the [$8 million] of downward revisions in the Eagle Ford?

Well, a lot of it was because of Wright and company's 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 they'll 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. And that's because of the B factor. And as you go out longer, probably get to year five or six is where you get to the 8% versus our 5%, which is out beyond ten years.

So there's a couple things going on. But we think over time -- time cures this problem, of course. But it is what it is, and we still feel comfortable in our internal numbers.

And then last question, just looking at your guidance for revenue and EBITDA, just because the -- 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?

Yes, Kim, they're definitely included. We still receive a significant amount of money from the hedged 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 when we start floating at 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% hedge on that incremental, below $70.

Right, okay. All right. Thanks a lot.

All right, thank you.

Sean Sneeden from Oppenheimer.

Good morning. Baird or John, maybe for you. But just given how your CapEx is front-end loaded this year, can you maybe talk about how you're thinking your PDP base decline progresses throughout the year? For instance, are you generally modeling it improving by year end from the 40% to 45% that we kind of saw in the end of the fourth quarter here?

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, but then they're sort of flat-ish between the third and the fourth quarter. You know, 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.

Okay, no, that's helpful.

Okay.

And then, Steve, maybe on liquidity, thank you for all the detail on the borrowing base assumptions. I'm just curious, how are you guys thinking about that fall redetermination? It looks like you're thinking that it will be roughly flat? Is that being driven by what you think you'll find in terms of reserve adds in your hedged book, or maybe any color around that would be helpful.

I think it's the latter. It is, 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 it has more value in the borrowing base. So we just feel it's a reasonable estimate to go with at this point.

That's fair enough. And with that being said, how are you guys thinking about, because I think you're pretty well funded for this year, but how are you thinking about planning for next year?

Just given your borrowing base in the hedged book are you guys thinking about larger strategic transactions where you might bring in a partner? Or maybe you could talk about how you think about the longer term funding plan?

A lot of it is going to be product-price driven. It depends on how long prices are in this range. But we have other alternatives, some of which you mentioned.

If this was a longer-term kind of issue, it's tough to speculate at this time exactly what we would do. But we have a number of options including sale of assets, bringing a partner in, as you mentioned. Whatever the case may be.

Do you think more so then by, call it midyear, that you would have a better sense of what the plan for 2016 will be?

Yes, I do. I do. We're going to have to keep our eye open 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 the second half of the year.

Okay, that's helpful. Thank you.

Gail Nicholson, KLR Group.

Hi, Gail.

Hi, good morning. Just looking at the upper Eagle Ford wells that are bring drilled in 2015. Are those going to be concentrated more in the Welhausen/ Martinsen area? Or are they going to be all over the acreage position?

They're going to be spread through our acreage position based on 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.

But nothing on the acreage that was acquired in eastern Lavaca?

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

Correct.

We have not completed it (multiple speakers).

Running production casing on it right now.

Okay, so to answer your question, we've already drilled one well on that acquired acreage.

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

Well, we want to get comfortable that oil prices are going to stay in a level that we think make a lot of sense. You know, make a lot of sense. Personally, I think we'd like to see it nudge closer to $70, $65 to $70. But at this point in time, if we can drive our well costs down, the 10% to 15% we were talking about, I still think we would 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 take a strengthening in oil price to get excited to want to add another rig as the year progresses.

Okay, great. And then just looking at the decline right in the upper Eagle Ford. Are you guys seeing any difference in the gas and oil volumes declining? Or are they declining at similar rates as you progress through time?

The GOR is staying relatively constant, so they're declining at the same rate.

Okay. Great, thank you.

All right, thank you.

Scott Hanold, RBC Capital Markets.

Hey, Scott.

Hey, thanks, Thanks for taking my question here, and good morning. A couple questions here, and maybe the first just on the upper Eagle Ford again.

When you step back and look at where you're spotting locations for 2015, can you give us a sense of how much of that do you think is going to be more testing, so maybe your acreage versus high level of confidence? When you step back and look at the range of EURs you've provided for the upper Eagle Ford, where on that scale would you point us to in terms of your confidence with your drilling.

It would be in the higher category. I think at this time, based on our drilling program in the second half of the year, and especially with this well we just drilled up in where Gonzales and Lavaca and Fayette county sort of come together. It gives us a lot of confidence that this thing is bigger than we originally thought it was.

So I think we have a high degree of confidence right now. There's always caveats to that, but I think we have a high degree of confidence in this upper Eagle Ford drilling program in 2015.

And so when you look at your 2015 programs in terms of where those bald spots are, is it a little bit more development versus exploration of the upper Eagle Ford?

That's correct.

Okay. And then one more question on 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 it make sense for you all to be in the Cotton Valley/Haynesville player in the mid-con region, would those be the first areas you'd look to shed off and become a pure play Eagle Ford player? Or would you have an appetite of just partnering with somebody in your Eagle Ford program?

Well, it's my opinion right now that I would not ideally like to dilute our interest in the Eagle Ford. I think if we're going to be a one-trick pony, I'd rather be a one-trick pony in Eagle Ford right now based on results and based on we do have a fairly significant gas component despite that they are oil wells. So it's not that we've eliminated our exposure to natural gas by standing the Eagle Ford by itself.

So in answering your question, yes, clearly, the East Texas stuff, since we really haven't spent any money there since roughly 2010, would be an asset considering that there's interest in those kinds of assets right now, especially with some of the Cotton Valley horizontal drilling going on and some of the Haynesville, even in today's gas prices, because the costs have come way down. So it just doesn't compete with what we have in the Eagle Ford at this time, but it's certainly an asset that we would consider selling, yes.

Okay. That's great, thanks, guys.

Thanks, Scott.

Adam Michael, from Miller Tabak.

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

No, I'm not going to comment. It's our policy not to comment on these matters.

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 what you'd expect to see in the lower Eagle Ford?

Yes, I think we think the spacing at this time would be the same as what we would expect in lower Eagle Ford. So the 400-foot criteria, we think, is a correct spacing on the upper.

Okay. And then in regards to the 80% of your acreage that you think is perspective for the upper Eagle Ford, was that something that there was like a certain thickness that was a cut off where 80% met that thickness? Or what's the reasoning behind the 80% number?

There's isopach reasons, or thickness reasons, as you stated. There is also result driven reasons based on the second half of 2014 program in the upper, so a combination as to -- plus this dingo well that we keep talking about up where Lavaca and Gonzales and Fayette come together really has been an eye opener as far as expectations in the upper. So that's the reason, and we've just got more data.

Okay, thanks for taking my questions, guys. That's it for me.

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

All right, thank you very much, and we thank you for listening in. There's no question this is a challenging environment, but we think we've made some major changes to our activity level in a very short period of time with our number one goal to protect liquidity, of course. But we're going to ride out this lull.

But the most important thing to remember as an investor is we still have a great asset, which gives us a lot of flexibility and running room once prices rebound. And we look forward to our May conference call. Thank you very much.

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.