EP Energy's (EPE) CEO Brent Smolik on Q2 2014 Results - Earnings Call Transcript

Aug. 8.14 | About: EP Energy (EPE)

EP Energy Corporation (NYSE:EPE)

Q2 2014 Earnings Call

August 7, 2014 9:00 am ET

Executives

Bill Baerg - IR

Brent Smolik - President & CEO

Dane Whitehead - CFO

Clay Carrell - COO

Analysts

Brian Singer - Goldman Sachs

Arun Jayaram - Credit Suisse

Nick Copeman - GLG

Michael Rowe - TPH

Joe Allman - JPMorgan

Neil Dingmann - SunTrust

Operator

Hello, and welcome to the EP Energy Second Quarter 2014 Investor Update Call. All participants will be in listen-only mode. (Operator Instructions). After today's presentation there will be an opportunity to ask questions. Please note that this event is being recorded. I would now like to turn the conference over to Mr. Bill Baerg. Please ago ahead.

Bill Baerg

Good morning, and thank you for joining our second quarter 2014 investor update call. In just a moment I'll turn over the call to Brent Smolik, President and Chief Executive Officer of EP Energy. You'll also hear from Dane Whitehead, Chief Financial Officer of our company.

Yesterday, we filed our second quarter press release announcing our quarterly results. During this morning's call, we will referring to the slides that are available on our website epenergy.com. Also, on our website in Investor Center Section you'll find a financial and operating reporting package that includes our non-GAAP reconciliations and other relevant information. We hope you will download this information, which is a helpful resource.

During today's call we'll make a number of forward-looking statements and projections. We have made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors that could cause actual results to differ materially from the statements and projections expressed during this call you'll find those factors listed under the cautionary statement regarding forward-looking statements on Slide 2 of this morning's presentation, as well as in other of our SEC filings. Please take time to review that.

Finally, EP Energy does not assume any obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events, or otherwise.

Thank you. I'll now turn the call over to Brent. Brent?

Brent Smolik

Thanks, Bill, and good morning everyone. Thank you for joining us today. I hope everyone has seen the recent releases that we filed with last week's operational update and in yesterday's second quarter earnings release. This quarter we had quite a few items to cover. So we provided an operational update last week ahead of our second quarter results after completing our Wolfcamp program analysis. I would also expect to file our 10-Q by the end of the week.

As in the past, this morning, I'll go through our quarterly operating results and highlights and then, Dane Whitehead, our CFO, will provide a financial and hedging update. And then, I'll wrap up at the end and have some time for your questions. In addition to Dane and I we also have Clay Carrell, our Chief Operating Officer, in the room with us this morning for Q&A.

So I'll start this morning on Slide 3. We had another excellent quarter and the year is shaping up to be even better than we expected, as we remained focused on executing on our plans and growing our business. All volumes in the second quarter were up 60% from the same period in 2013, with all three oil programs contributing to our growth. Total all volumes were more than 53,000 barrels a day, which is again another EP Energy record.

And we continue to realize the financial benefit of that growth for the second quarter, adjusted EBITDAX from continuing operations of $372 million, up 50% from Q2 of 2013, before considering the impact of hedge settlements in both periods.

During the quarter, we completed the previously announced acquisition of additional acreage in West Texas, in the Wolfcamp with 475 drilling locations added to our program. We also completed the sale of non-core assets in South Louisiana Wilcox and the Arklatex areas. In total, we made excellent progress on our plan for the year and our growth in the first half of the year supports our increased full year outlook.

On the execution side, we remained focused on improving operational efficiencies. And all of our capital programs continue to deliver improved results with higher returns and record activity levels. We completed 68 new wells in Q2, which is more than we've ever done before. Also this quarter you could see the impact of our completion optimization efforts and increased frac stages per well as we completed over 1600 total frac stages, which is up over 20% from Q1 of this year.

We have also increased our Wolfcamp type well EUR and type well economics based on improved production performance from our B/C development program. And then, finally, our completion and production optimization efforts in our Eagle Ford and Altamont programs continue to deliver improved early production results.

In addition, in near-term performance, we remained focused on multiple longer-term value drivers. The single largest upside to higher net asset value for our business has still increased efficiencies across our total company inventory of over 5,600 future drilling locations and we have continued to develop strategies and activities to enhance that value.

In the Wolfcamp, we drilled our first A zone wells. We have added a couple more wells to our 2014 program and we still expect to have results from the a-test later this year.

Slide 4, includes our standard table summarizing the results of another really good quarter. As I mentioned in the second quarter, we completed 68 wells in our three core areas. And we highlight this statistic because it's such a significant driver of production growth. It's not the only driver; there is other variables like production uptime and new facility timing and downstream third-party performance. But the number of new completions and even the timing of those completions within the quarter matters a lot to our quarterly production volumes.

And as you recall, last quarter I said we added a fourth drilling rig to our Wolfcamp program at the very end of Q1, which means that most of the new completions from that rig will come online in the second half of 2014, a lag of about a quarter.

We routinely compare actual production results to predicted volumes based on the intra-quarter timing of the new completions to validate our own type wells and our production forecasting models. And based on that analysis, we still expect production growth each quarter in the second half of the year going forward.

In the second quarter, our activity remain focused on Eagle Ford, Wolfcamp, and Altamont areas and our forecasted production showed up nicely with total equivalent production growing 21% from the second quarter of 2013.

Eagle Ford is our largest program and it produced 50,500 barrel a day of equivalent volumes.

In Wolfcamp, we continue to ramp up volumes quickly. In the second quarter, we produced just over 14,000 barrels of oil equivalent per day. You will also see that our gas production is higher in the Wolfcamp as a percent of total production, compared to the first quarter. And this is a result of capturing and selling more gas and associated natural gas liquids, as we added new field infrastructure and expanded the development across our acreage.

Altamont continued its significant growth with 15,700 barrels a day of equivalent production and these again are all record quarterly volumes in all three of these oil assets.

In the Haynesville program, we produced 16,300 barrels a day on an equivalent basis in the quarter, bringing the total production to 96,700 barrel equivalents per day.

Slide 5 shows our oil volume growth in the three programs and the total for the company. Again, Wolfcamp ramped up significantly from the same period last year. And Altamont, which has been delivering double-digit growth for many years, got off to a really good start in the first half of the year and it's at 41% year-over-year for Q2.

Eagle Ford, which is still currently our highest returning program, again delivered outstanding production growth, as we continue to improve execution in that program. We are one of the earlier operators in the Eagle Ford play. And through continuous improvement efforts, and a diligent focus on returns, the Eagle Ford developed into a franchise program. Although, the Wolfcamp is earlier stage, we see a lot of similarities there to our Eagle Ford program as we apply the same type of approach and the same discipline to the Wolfcamp development.

Moving to our capital program detail, Slide 6 highlights our Eagle Ford position. The Eagle Ford story in the quarter was largely driven by two factors improving production operations and improving initial rates per well from better completion designs, while holding the line on CapEx per well. We remained very active in the Eagle Ford program focusing on LaSalle County, where our acreage in the heart of the Black Gold and (inaudible) fairways.

We currently have five rigs running along with two frac rigs and we completed 34 wells in the quarter. And we plan to keep those five rigs drilling actively here for the rest of the year. The chart on the right shows that once again we grew production in the quarter. Again, partially attributable to improved production operations, including improved production runtime or uptime, which helps to reduce unit lifting cost.

We continue to strengthen this program and build longer-term value. We also remained focused in a couple of areas. We initiated testing of 40 acre well spacing in the second quarter and we continue to test shorter stage spacing and higher profit volumes, as we continue to evolve our completion techniques.

Slide 7 includes as map of our entire Eagle Ford position in LaSalle County and the results of our most recent wells. All of these wells are benefited from our completion optimization efforts in the higher initial producing rates on these completions with a second major driver of higher Eagle Ford production in Q2. The chart includes oil and total equivalent production volumes per well. And we've included the well detail here since we report the data to the state on the lease level. And as you know, it can be difficult or impossible to see trends and improving well performance and lease level aggregated production.

We are seeing very exciting results from north to south across the acreage block with one of our best wells in the southern end our block with over 900 barrels of oil per day and over 1500 barrels of oil equivalent per 30 day averages. Both our oil and equivalent 30 day producing rates are exceeding our type curves on most of these recent wells.

The additional good news is that we have been able to offset the cost of the increased number of stages and increased amount of profit per well with our supply chain management activities, our proppant and fluid design changes, and our improved completion time and cost efficiencies.

Slide 8 highlights our growing and evolving Wolfcamp program. The chart on the left side shows the success of our operations and the rapid growth of our oil volumes, which average nearly 8,000 barrels a day in the second quarter. We added a fourth rig in late March, which will result in growing completion counts in the second half of 2014, as I discussed earlier. Remember last fall, we shifted our development model from drilling Wolfcamp B wells and a very concentrated narrow corridor to drilling combined Wolfcamp B/C wells more broadly across our acreage position.

We completed 23 wells in the second quarter and as we increase the activity we also expanded our fuel facilities in the quarter to keep up with our growth and to better optimize our daily production operations. Again, the startup for these facilities had a positive impact on equivalent volumes for higher gas and NGL sales in the second quarter.

We expanded the Wolfcamp asset in the quarter with the bolt-on acquisition at the end of April, which we talked about in our last call. And again, the transaction added 475 drilling locations and about 25% more university land acreage, which we've now intergraded into our daily operations.

I am very pleased with the purchase. It's the type of transaction that fits well with our strategy. It's a large position adjacent to our existing footprint with good scale and repeatability, which allows us to create additional operational efficiencies. At the end, efficient and low cost allows us to be a natural consolidator in these types of repeatable plays.

In the quarter, we started to drill Wolfcamp A wells, and test that zone in both our western and eastern portions of our block, as we continue to fully delineate our acreage position in all three Wolfcamp intervals. The log and core data for the A zone indicates that it has the highest organic content and the highest porosity, which suggest it has the highest oil in place of all three zones. We now plan to drill seven A zone wells this year across our acreage block and should have completion results on most of them later this year.

As you can see on the chart, again we averaged 8,000 barrels of oil per day for the quarter. But what you can't see on the chart is that the month of June production was up to 9,000 barrels a day as completion activity increased throughout the quarter.

Slide 9 highlights our updated Wolfcamp type curve and a type well economics. The update is a -- it's both an important near-term production and cash flow story and the long-term value story for this asset. The updated type curve reflects the results of the combined B/C development and our completion optimization efforts, including tighter frac stage spacing and increased amount of proppant per lateral foot. This design is expected to generate a pre-tax NPV of about $1.2 million or 43% higher than the previous type curve for the long laterals and it includes a relatively modest 5% increase in our estimated well cost.

The $300,000 per well CapEx increase is driven by increased completion cost. And this is our view today. But we're not done with our optimization work here and we will work to enhance our performance here just as we've done in all of our capital programs.

As I mentioned earlier, these types of efficiency gains over a $1 million of NPV per well, are extremely leveraging to NAV growth when applied to our 3400 well inventory. We have also updated our Wolfcamp program inventory in the table to 2780 long laterals and then we have got 595 short laterals as of the beginning of this year and after including the April acquisition.

We think this type -- the type curve improvement is a great example of our development success. It's the third time, following the Haynesville and the Eagle Ford, that we have organically built the program from modest beginnings into franchise assets by successfully flying our execution model.

Moving to the Altamont on Slide 10. The production chart on the right shows our Uinta Basin oil volumes, which have drawn significantly this year and especially in the second quarter. The story in Altamont is simply exceptional performance across the board in all aspects of our business, including drilling time and cost, completion design and cost, production operations, and in crude oil sales and marketing. We just had a great quarter in Altamont.

We completed 11 wells in the second quarter and had three rigs running for most of the quarter, having moved back to the three rigs in April. We expect to continue with the three rig program during the remainder of the year. And while this program has delivered steady growth for a long time, I feel that some people overlook our Altamont production growth and our track record here. Over the past few years we've significantly grown Altamont production, while at the same time lowering average well cost.

Importantly, we've also stayed ahead of our growth and maintained adequate downstream capacity in markets. Our operating marketing teams did an excellent job of moving our crude and increasing our takeaway options in the quarter. As we look ahead, we expect additional refinery expansions to come online and bring basis differentials more in line with the historical norms in the basin. Dane will cover that a little bit more in his section.

And as a reminder, we are currently developing the field with vertical wells on 160 acre spacing and also actively participating with others in the industry and testing tighter spacing, which we continue to believe will add inventory of future drill wells in the Altamont area.

Slide 11 highlights the continued improvement we've seen in our Altamont completion program. The chart on the right shows the IP 30 progression for our program and the steady improvement we've been able to achieve there. During the quarter, we drilled three of our all time best wells in the program and that's dating all the way back to the acquisition of the field in 2001. Year-to-year our IP 30 rates have averaged 587 barrel equivalents per day or about 12% of our type cure. The primary drivers of that improvement has been expanded and at the same time more targeted completion intervals, increased proppant volumes, and improve fluid designs are utilizing thinner less viscous to frac fluids. So we really like this asset and I think its vast resource space, provide significant upside and additional running room for the future.

So I'll now handoff to Dane to cover the financial results.

Dane Whitehead

Thank you, Brent. Good morning all. And thanks for joining the call today. As Brent noted, we filed our earnings release yesterday and posted our Q2 2014 detailed financial and operating reporting package before on our website this morning. We also expect to file our 10-Q by the end the week.

A quick housekeeping note on our financials before I jump in. As a result of the sale of our South Louisiana Wilcox and Arklatex assets in May, we reclassified those assets as discontinued operation this quarter. All the information in this quarter, and in our future filings, excludes from all periods the volumes and financial results associated with those assets, and other assets classified as discontinued operations. I won't go in all the detail here, but the impact on 2013 and 2014 results is detailed in the form.

So with that, I'll start in Slide 13 with the Q2 financial highlights.

We delivered another quarter of excellent operational and financial results. We are also updating our full year outlook to reflect a higher growth forecast. And I'll cover that at the end of my section.

Our operational success continues to drive adjusted EBITDA growth and expand our unit margins. With our updated outlook, we now expect our Eagle Ford and Altamont programs well each generate significant positive free cash flow for the full year of 2014.

Cash costs were in line with our expectations in Q2. And although there were some one time lumpiness in the quarter, our full year outlook for cost is in line with our original guidance. We continue to maintain significant financial flexibility and we ended Q2 with $2 billion of liquidity. So in summary, we maintain our strong momentum with another quarter of outstanding results.

Slide 14 provides a summary of our second quarter results. Oil production grew by 60% year-on-year and increased to 55% of total production, that's up from 42% of total production in Q2 2013, as we continue to execute on our strategy to grow our highest margin assets.

Adjusted earnings per share was $0.23 and adjusted discretionary cash flow per share from continuing operations was $1.19.

Adjusted EBITDAX was $372 million in the quarter, up 41%, compared to $264 million in Q2 2013. Excluding hedge impacts adjusted EBITDAX grew 50% year-on-year, reflecting the strong returns being generated by our business. This is further evidenced by increases in our unit margins, which grew by 17% to over $42 a barrel.

Our balance sheet is also stronger than it was a year ago, driven in part by a strong year-to-date cash flows.

Slide 15 provides a summary of our second quarter capital expenditures by program. In Q2 2014 our capital was $558 million, up from $504 million in Q2 2013. This excludes our Wolfcamp acquisition capital of $152 million, which was largely offset by divesture proceeds. We completed 68 wells in Q2 2014 compared to 62 in Q2 2013. As demonstrated by our production growth, the 2014 wells in every program are more productive than they were last year.

And note, that if you do simple pro-well map comparing this quarter to previous quarters, you will see some variations in well cost. This is due primarily to the timing of spending in the quarters versus actual completion dates. We're very comfortable all that our pro-well cost for the year will be in line with program guidance.

Our budget anticipated weighted average well level returns of 45%. We now anticipate weighted average well level returns to be close to 50% from our 2014 capital investments.

Moving to Slide 16. This demonstrates our year-on-year growth in unit margins and provides some detail on unit costs. The metrics were on a pro-barrel basis and exclude hedging impacts. Adjusted EBITDAX margin grew by $6.22 per Boe to $42.25 in Q2 2014, that's up 17% from Q2 2013 and reflects the increasing oil as a percent of our total production mix.

Our adjusted unit cash cost during the same period grew by $2.17 per Boe to $14.88. There are some one-time costs in the year-over-year comparison that makes that unit cost grow, look higher than the underlying trend and I'll point those out in a minute. Without those one timers, adjusted cash cost in Q2 2014 were in-line with costs in Q2 2013.

Unit LOE is up slightly year-on-year. We do expect unit LOE to trend down in the second half of the year as we continue to complete infrastructure on our developing oil programs. In our more mature Eagle Ford and Altamont programs, unit LOE declined in Q2 as production growth outpaced costs.

In Wolfcamp, we anticipated similar trend going forward, as we grow volumes and reduce startup costs related to temporary facilities and our expanded development areas.

Adjusted unit G&A was lower in Q2 2014 due to lower staffing cost and higher volumes.

If you recall, we have a legacy cash LTI program for non-officers that we put in place when we were a private company. The cash payments are largely made in Q2 of each year. We record the total cash payment in our adjusted G&A in a period paid rather than expensing it ratably throughout the year and this creates lumpiness in the second quarter.

In Q2 2014 cash LTI was approximately $1.41 per Boe. Without it, our adjusted net G&A run rate was approximately $390 per Boe, which is in line with our expectations for the rest of the year.

Now, that we are public, the cash LTI program has been replaced with market based equity LTI program. And the cash program should have a less significant impact going forward as it runs off over the next couple of years.

Production taxes increased year-over-year as expected, due to revenue growth from higher value oil production. Think of production taxes as approximately 6% of revenue, which will vary with commodity prices and production mix. Other taxes is up due to the fact that in Q2 2013 we settled a sales in used tax matter that resulted in a one-time credit of $12.6 million or a $1.73 per Boe one-time reduction in Q2 2013 unit costs.

Adjusted for this item, other taxes would have been flat period-over-period.

For the full year, our cash operating and costs are expected to be 1290 to 1390 per Boe with a $0.15 higher midpoint from earlier guidance being solely attributable to higher production taxes on higher revenue. Transportation cost is $3 to $3.25 and down $0.13 at the midpoint. In combination unit cash costs are flat to original guidance, which should support ongoing growth in our unit margins, as we continue to grow our oil production.

Slide 17 shows our realized prices by basin as a percent of WTI. I am focusing here on sequential quarters Q2 2014 compared to Q1 2014, the industry current trends which reflect our outlook on pricing better than 12-month old numbers. These oil price realizations include locational basis differentials, along with customary refinery postings, and contract pricing deductions, things like handling charges.

All hedging impacts are excluded to provide visibility into underlying trends. Note that in Q2, our total company oil price realizations before hedges were $95.04, up $2.14 due to stronger index prices. That said we did see wider basis in some areas.

In the Eagle Ford, we realized 96% of WTI in Q2 2014, which was down slightly from 98% in Q1 2014 about a $2 change in basis. A significant portion of our Eagle Ford production is currently indexed to LLS pricing. We've seen that LLS premium to WTI come down steadily over the last year. And we anticipate more stability in LLS prices as we move forward in 2014.

Permian differentials and our Wolfcamp realization has moved lower in Q2 2014. The volatility was driven by multiple refinery outages and a delay in the in-service date for the BridgeTex pipeline. We expect this to improve in Q3 as most of the refineries have already come back online and BridgeTex begin to line fill in August.

Over the last six months, Altamont pricing has been at the low-end of the five-year historical realization range, which has been 83% to 87% at WTI. We saw a slight improvement in Q2. We expect the addition of rail capacity much with the out of state markets plus refinery expansions in Salt Lake. We will continue that trend as we move through 2014.

Slide 18 provides a summary of our hedges as of the end of the quarter. Note that the 2014 hedged statistics and volumes are for the period from July through December of 2015 and 2016 are for the full year. And the hedged percentages for all periods are based on the midpoint of our updated 2014 volume guidance.

For the balance of 2014, we have oil production floored at an average price of around $98 and we've got a very significant portion in 2015 and 2016 floored at above $90. In Q2, we added about 3.7 million barrels of 2016 oil hedges; these were 80 by 90 by 99 LLS three-way swaps. The $90 foot price is included in the average floor price on the chart, but there is solid upside on those positions if LLS settles above 90.

For your reference at the bottom of the slide, we've broken out Eagle Ford's specific hedges. The new LLS three-ways effectively hedge our Eagle Ford production so they are included in that section as well. Moving forward, we will continue to look for attractive opportunities to lock in additional oil basis in Eagle Ford and Wolfcamp.

On the natural gas side, we are also well hedged in 2014 and 2015 at above $4 in MMBtu.

Slide 19 is a summary of our new outlook for the year. As a result of increased performance in our oil programs, we're raising our outlook and our production guidance for the balance of the year. Our new range of expected oil production is 54,000 to 56,000 barrels per day. At the midpoint, this represents a 52% year-on-year growth rate. 2014, total equivalent volumes are now expected to be 96,000 to 100,000 barrels of oil equivalent a day. At the midpoint, this represents 21% year-on-year growth.

For the balance of 2014, we plan a very efficient level loaded rate program of five rigs in Eagle Ford, four in Wolfcamp, and three in Altamont. We have also updated well completions. Altamont and Wolfcamp are unchanged. We've shifted some capital within the Eagle Ford program and now we expect to complete a 125 to 130 wells for the year.

As Brent mentioned, we plan to keep five drilling rigs running for the remainder of the year. Because our rigs are running very efficiently, we expect to drill 15 to 20 more wells than originally planned, which will allow us to build a modest Q4 completion backlog. We also expect our full year mix of wells to have a higher than planned working interest.

On balance, we are pleased with this outcome. The fact that we can increase our full year outlook with fewer completions is a tangible sign of our improved initial production rates in this program. We also have the option to complete a few more Eagle Ford wells late in the year. As discussed earlier, our per unit cash costs, including transportation expense are in line with earlier guidance. DD&A rates are actually a bit better.

So in summary, we remained focused on delivering results with continued growth and a rapidly improving financial outlook.

With that, I'll turn it back over to Brent to wrap up.

Brent Smolik

Thanks, Dane. So I'll just close with a few key takeaways from today's call, which are summarized on Slide 20. We had another strong quarter. We continue to execute well with better than expected results. Our oil programs are producing record volumes for us with expanding unit margins, which results in rapidly growing cash flows. Production per well improved in all of our oil programs providing strong support to increase our outlook for the second time this year. And we have enhanced longer-term value by increasing inventory, by increasing efficiencies in margins, and by improving the type well economics for our Wolfcamp program.

So it's another exciting quarter, which we expect to build on for the second half of the year. Our team has been together for a number of years now and we have created a lot of value. And we feel that in many ways EP Energy is just getting started with many exciting opportunities still ahead.

So with that, thank you again for your interest in the EP Energy story. We'll now take your questions. Operator?

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. (Operator Instructions).

And our first question comes from Brian Singer of Goldman Sachs. Please go ahead.

Brian Singer - Goldman Sachs

Can you talk more specifically about the types of completion enhancements you are pursuing, whether they differ in the Eagle Ford versus the Permian versus the Uinta, and then, in the Eagle Ford specifically, you highlighted the 30-day rates are trending above expectations? Can you just talk about how that can impact EURs and well costs, please?

Brent Smolik

Yes. Generally, Brian, this is Brent. Generally, I think you should think about greater number stages in the horizontal wells and a higher proppant loadings in the horizontal wells being Wolfcamp and Eagle Ford. Altamont is kind of its own animal. Remember, its vertical well completion. And I think the story there is, it is higher proppant concentrations, but it's also adding greater intervals to the original completion to a thickness of interval to the regional completions. And being more selective about how we're getting them done. We are just getting better across the board at how we are fracking those wells in the Wolfcamp and in the Altamont field.

And now, I'll let Clay give you some specifics about the Eagle Ford play. But on your question on the 30-day rates, I mean the honest answer is, we don't know. We drilled -- the completion design changes are definitely impacting early production. And we drilled it, that you can see it all the way up to the total second quarter, actual production results that we're getting out of that program. And I think it remains to be seen it for if it's mostly rate acceleration or if we're going to get an incremental reserve uplift of it. But the near-term impact is really exciting and improvement in returns is really exciting. Clay, may you give him a few specifics about the Eagle Ford?

Clay Carrell

Hello Brian, Clay Carrell here. The -- in Eagle Ford the shorter stage spacing and increased proppant per lateral foot consistent with Wolfcamp. But we're also utilizing more white sand in the conversation now where we had been exclusively resin-coated sand in the Eagle Ford. So that's a little twist different than the Wolfcamp.

Also, on the go forward cost on Eagle Ford, we feel like those will continue to be at our planned numbers of $7.2 million drilled and complete. In the Wolfcamp, as we've added stages due to the tighter stage spacing and increased proppant, those well costs have increased, tied to the bigger jobs. In Eagle Ford we get the benefit of lower cost tied to going from resin-coated sand to white sand that helps offset that as we go forward. And then, we're seeing cost reductions in Altamont even with the completion optimization as Brent mentioned.

Brian Singer - Goldman Sachs

Great, that's helpful. And then going to the Wolfcamp A, are there any -- are there any early looks you had at well results yet, or is it just too early? And then, how are you planning your delineation aerially between the -- the -- the two blocks you have in the -- or the -- the -- the different areas within -- within the Permian?

Brent Smolik

Yes. Brain, no production results yet. We started drilling and we've started completing on the A program. And we're still looking to get results out in the second half of the year for those. But remember, we pointed to in the call just now that that's the zone that has the highest oil in place of the three and so we are optimistic that it's going to be as good as the others, and be able to deliver that type curve that we just updated for the full area.

As far as how we're doing them, we're spacing them, think about it across the block there are probably about 40 miles Permian, Dean. And a pilot test will be doing this year. So we think if it is broadly across the acreage position.

Operator

Our next question comes from Arun Jayaram of Credit Suisse. Please go ahead.

Arun Jayaram - Credit Suisse

I wanted to see if we could may be dig down and -- and review Slide 7. I have some questions regarding that -- the -- your recent Eagle Ford results. My first question is -- is, are the last -- I think there's 21 wells, here -- in this slide. Are these the last 21 wells that you have drilled using the new completion design, i.e., are there -- are all these the wells, or have you cherry-picked some of the data, here?

Brent Smolik

No, there is no cherry picking Arun. These are just the recent wells that we've used, the newer completion designs and we've got at least 30 days of production on them.

Arun Jayaram - Credit Suisse

Okay.

Brent Smolik

So there is no high grading or cherry picking other than that. We think that broadly the completion design changes are going to apply across the block from north to south. And we think we're optimistic, it's going to improve oil production across the block north to south by using the new completion technique.

Arun Jayaram - Credit Suisse

Okay. I -- I just did some math around it. I calculated that the IP 30, the northern 16 wells was over a thousand Boes, about 82% oil. There's about I think, five wells in the south, again, over 1000 Boes, but 60% oil. Can you just talk about the fact that I think your type curve is based on 500 Boes of oil, but does it -- was it surprising to you guys that it gets a little bit gassier, or is this -- was this embedded in your overall type curve for the central block?

Dane Whitehead

That's a great question. As a reminder, for everyone, that we're convinced that the entire acreage position is in the oil window. But we've always acknowledged that the northern end of the block is what we refer to as the black oil trend and the southern end of the block is the volatile oil trend. But both of them are oil and the reservoir. And it's not surprising that we get higher gas associated with the oil production as you move south.

But the big driver here remember is oil production. And the oil production as you rightly point out is higher in both the north and the south. It's even higher in the north, but it's higher than our type curve in both the north and the south part of the field. And so I think it's going to -- the new compression techniques at least early on look like they're going to apply broadly.

Clay Carrell

So, Arun you said 500 Boe. 500 is just oil, barrels of oil a day.

Arun Jayaram - Credit Suisse

Yes, just -- just -- just oil, that's exactly right. I'm sorry about that. Okay, so the bottom line here is the wells are meaningfully outperforming your type curve using the new completion design in the north and south?

Dane Whitehead

That's it.

Arun Jayaram - Credit Suisse

Okay.

Dane Whitehead

That is the message we're trying to convey.

Arun Jayaram - Credit Suisse

Okay, and just second question is if you go to Slide 9, obviously you just raised your Wolfcamp type curve. On Slide 9 you show the updated type curve in green versus your previous one in black. You do show that the lines, as you get into months seven, eight or nine start to compress a little bit. Dane or Clay, could you just talk a little bit about that compression, and -- and just overall thoughts on that, the new type curve?

Dane Whitehead

Yes. I'll probably defer that one to Clay. But the initial production is clearly higher and we've been signaling that for several quarters now. We've got cumulative production 10,000 barrels a day or so or more in the first 100 days than we had of the old type curve. So we've been signaling the early production is better. And then, we have used all our best engineering estimates and judgments to be able to forecast how that's going to look over life. But if it starts better that bodes well long-term.

Clay Carrell

We think it's consistent with what we have been showing that early time performance has been ahead. This type curve update gave us an opportunity to apply a better shape to the type curve consistent with what the actual production performance has been. The increase is front-end loaded that we see with the elevation in the EURs but if they do begin to come closer together over time.

Operator

Our next question comes from Nick Copeman of GLG. Please go ahead.

Nick Copeman - GLG

I have two questions for you. One is on the Eagle Ford. And I think quite a bit of commentary from analyst talking about the southern part of your acreage. And potentially you're not meeting the reserve versus (ph) numbers so you have to take the reserves right down there? And the second was just from the Wolfcamp. Wondered how close you to the Wolfcamp D well in Upton and Pioneer (inaudible)? Thanks.

Dane Whitehead

And maybe I'll take the matter in reserve order, Nick. The Pioneer wells is probably about, say about 15 miles, into 15 miles north of us. Well, that's right near the Reagan/Upton County line and if you just go straight down that county line you hit our acreage. The --

Nick Copeman - GLG

Do you -- do you -- do you not see any geologic differences to where you are and where they are?

Dane Whitehead

I think it's going to be more naming convention. I think the rock is going to similar when you move from north to south across the Basin it's a little deeper but other than that it's similar. We would probably call that Cline Shale. I think what they're pointing to is the Wolfcamp D we would call the Cline, if you look at some of our older public materials that are out there.

And I think in general commentary, any time we have positive results in or around our area that they can help de-risk our acreage for us -- that's always great news for us.

In terms of the Eagle Ford South, I mean we hear some of those saying that same commentary, as part of the reason why we're showing you these recent well results. I don't know if some people are looking at trying to tease out individual well data out of lease data or if they are looking at older generation completions when they -- I don't how to comment on what other people are saying.

But what we're trying to show you here is that that we think we're going to be able to apply the current completion techniques across the block and we're getting good results from the recent wells.

Nick Copeman - GLG

I guess it is a question on how your reserve auditors are looking at the data, are they comfortable with new completions, and do you think that will apply back across your reserve bookings so you wouldn't get down grade, or do you think they would look at legacy production more?

Dane Whitehead

Yes. In terms of our reserve auditors, we have very little variation in the reported reserves across our whole reserve database. And this field is no exception. We have a very small variance between our reserve auditors and our estimates across the portfolio and we have very small variance here.

Operator

Our next question comes from Michael Rowe of TPH. Please go ahead.

Michael Rowe - TPH

Just wanted to make sure I understand the production guidance increase. So I guess are you all now, for the second half of the year, baking in the 450 MBoe Wolfcamp type curve for all -- all your well completions?

Brent Smolik

Yes. And I think that's a fair statement across the board. I mean, we -- anytime we update guidance, we look across the programs. And we're using our most current view of not just the type curve but the activity levels and timing and everything that comes along with it in terms of the cycle times. And so yes it includes it for the Wolfcamp and it includes the recent results we have had in the Eagle Ford and Altamont.

Michael Rowe - TPH

Okay. And so that would be I mean, that's how you are getting from the fewer well completions in the Eagle Ford but still kind of getting the same, if not better production because you're getting some of the uplift in the second half of the year from the enhanced completions?

Brent Smolik

It's definitely one of the drivers. The second quarter results matter and the full year guidance that we're giving. And we outperformed in the second quarter. But then, we used the same forecasting go forward. Yes. And so, we got today about, if you look at midpoints like 12 or 13 less completion scheduled in the Eagle Ford as what Dane pointed out. And we are offsetting that with higher initial rates per well in order to be able to get the higher total year guidance.

Michael Rowe - TPH

Okay, that's helpful. Then, I guess just wondering, can you kind of remind us, just as you think about your -- your large and growing inventory in the Wolfcamp, and the potential for the 40-acre down-spacing adding to your inventory and the Eagle Ford, and expanding well locations there. Can you just talk about how you think about potential acceleration case, and -- and if there is a certain level -- level of leverage that you're comfortable, where you are comfortable accelerating at?

Brent Smolik

We haven't really guided the different longer-term higher capital cases that's what you're getting at. I mean, the logical places for us to accelerate, if you just look at the depth and quality of our inventory are Wolfcamp and Altamont, those have the longest inventory lives. What would motivate us to want to go faster in the Wolfcamp is, if we can continue to see higher returns at the well level. And you saw an improvement in returns in this type curve. And then, any additional improvement in the EURs and rates or lower CapEx would enhance that even further.

And so that would be our thinking about where and why we would likely increase CapEx. But we're going to be disciplined about the balance sheet along the way. And so I don't think we're comfortable guiding the higher accelerated cases today on the call. But probably that helps you, at least I will think about it. Today our all end returns on a capital program that Dane highlighted for you is about 50% this year based on our estimate in current prices. And if we can continue to get that kind of return on average by allocating capital between these three oil programs then that's a great growth profile.

Operator

Our next question comes from Joe Allman of JPMorgan. Please go ahead.

Joe Allman - JPMorgan

So looking at Slide 9, because you have you so many data points, especially early on, it is hard to really distinguish the newer wells from the older wells. So are the most recent wells after you've made the transition from just focusing on a B in a very narrow area, to the B/C over a wider area, are the most recent wells performing in line with the 450,000 Boe type curve, or are they actually performing better than that type curve?

Brent Smolik

I think on average is what always matters; they are performing in line with the new type curves we're guiding to and that's part of the justification for changing it. But I think if you were able to see individual well data, you would see a variation that contributes to that average across the block. And then, there are things that we have to deal with like as we spread out the development program and we add new facilities some of the newer wells are coming into sub-optimized facilities and so at an individual well level they may be below the type curve. But what matters -- and ultimately, the production and cash flows that we generate the average and the new wells are at the type curve or above on average.

Joe Allman - JP Morgan

Okay, that's helpful. And then back to Nick's question about the Cline, is the Cline prospective on your acreage? And if it is prospective, might there be a problem because of the depth relative to some of the stuff up north, and could you just talk about that, if you have any plans to test that?

Brent Smolik

Yes. The only testing we have done is, we drilled a vertical well about a year ago now, may be a year-and-a-half ago. And we did a lot of coring and science on that well. And we actually completed it as a Cline well for a short period of time, a vertical Cline well. So we know that the Cline is present and we know that its hydrocarbon saturated and we know that it's a target zone. But we haven't yet pilot tested it in terms of horizontals.

So it's in our longer-term thinking. And I think there is a -- it's a very good change that it's going to get drilled at some point in the future and it's going to get added to the inventory at some point in the future. So we have always pointed to hit and the Sprayberry as future outside potential.

Joe Allman - JP Morgan

Got you. Okay, and then just quickly on the Uinta -- any plans to drill horizontal wells for the (inaudible) and/or the Wasatch? Just thoughts about the prospectivity under acreage? And then, what's your ability to continue growing at a nice clip in the Uinta?

Dane Whitehead

So we had talked about earlier doing a couple of horizontal wells this year. But the vertical program is working so well that I don't think we'll do that this year. I think we'll stick with verticals and we'll continue to watch what others are doing. We noticed some of the recent results on some of the horizontal wells are getting better and the returns on those are starting to compete with our vertical well returns. And so we'll keep watching it. And it definitely has potential on our acreage. We've got it included in our guided inventory. We've got -- Clay, how many wells?

Clay Carrell

350 wells.

Dane Whitehead

About 350 wells or so that we count for horizontal potential. But Joe, we really think of it is -- it's really just a what's the most efficient way to develop the field and the most efficient way to maximize the value, can't think of it per section. And if -- we may choose long-term to drill tighter space vertical wells. We may choose to drill a combination of vertical and horizontal wells, the way we've got it catalogued in our inventory. And it's really just a question of what's the best way to optimize returns and value.

Operator

And our last question comes from Neal Dingmann of SunTrust. Please go ahead.

Neil Dingmann - SunTrust

Good morning, gentlemen. Just two quick, mostly -- both on the Wolfcamp. On that acreage you added there in the south -- I think I know the answer to this based on earlier answers -- but given it is a little bit shallower there, any reason to complete that any differently than -- than the rest, or will that continue to be just like the rest of the program?

Brent Smolik

No, it's not even shallow. I think depth is more -- if you think about it as southeast and northwest, would be the way the depth is. So it's deeper than some of our acreage is further east of it. But the rock section most importantly looks very similar to us. The thickness, the porosity, the organic content all of the important drivers are all in place and productivity look very similar to us on that block. And so I wouldn't expect the completions to change dramatically.

And in fact, we've done some work down there. Since the acquisition, we had three wells that we -- that were completed but not yet tied in the facility. So we've got those wells tied in. And then, we've got about five well -- four wells down there that have been drilled but not yet fracked. And so we'll put those into our fracking plans.

And so we've already integrated the production operations in a really short timeframe here. Production operations are all integrated in and we started to do work on the wells. So pretty soon you'll hear us talking about that as just a Wolfcamp program and it will all be rolled in, rolled into one.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to management for any closing remarks.

Brent Smolik

Okay, with no questions, and I'll just conclude by saying that we are really pleased with another strong quarter of growth and execution on our plans. We really appreciate everybody's interest in the story. And we really appreciate our supporters our there. Thank you.

Operator

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.

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