Eclipse Resources (NYSE:ECR)
Q2 2016 Earnings Conference Call
August 3, 2016 09:00 ET
Douglas Chris - Manager, IR
Benjamin Hulburt - Chairman, President & CEO
Tom Liberatore - COO
Matthew DeNezza - CFO
Neal Dingmann - SunTrust Robinson Humphrey
Holly Stewart - Scotia Howard Weil
Kyle Rhodes - RBC Capital
John Nelson - Goldman Sachs
David Deckelbaum - KeyBanc Capital Markets
Ronald Mills - Johnson Rice & Company
Gabriel Daoud - JPMorgan
David Beard - Coker and Palmer Investment Securities
Matt Sorrenson - Seaport Global
Good morning. And thank you for joining us for the Eclipse Resources Second Quarter 2016 Earnings Conference Call. I'm Douglas Chris, Manager of Investor Relations and with me today are Benjamin Hulburt, Chairman, President, and CEO; Thomas Liberatore, Chief Operating Officer; and Matthew DeNezza, Chief Financial Officer.
If you have not received a copy of last night's press release regarding our second quarter 2016 financial and operating results, you can find a copy on our web site at www.eclipseresources.com. We will spend a few minutes going through the operational and financial highlights, and then open it up for Q&A.
Before we start our comments, I would like to point out disclosures regarding cautionary statements in our press release and remind you that during this call Eclipse management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Eclipse Resources and are subject to a number of risks and uncertainties, many of which are beyond Eclipse Resources' control.
Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Information regarding these risk factors can also be found in the Company's filings with the SEC.
In addition, during this call, we do make reference to certain non-GAAP financial measures, reconciliation to applicable GAAP measures can be found in our earnings release. We will file our 10-Q later today which will be accessible through our web site or the SEC's Edgar system. Lastly, we will be participating in the upcoming EnerCom Conference in Denver.
I will now turn the call over to Benjamin Hulburt, our Chairman, President and CEO.
Thank you, Doug and thank you to everyone for listening to our call today. I'll begin by reviewing what Eclipse Resources accomplished during the quarter. During the quarter, our average daily production was 212 million cubic feet equivalent per day, excluding a 24 million cubic feet equivalent per day revision to prior period estimates. This production level, before the upward adjustment, was above our targeted rate under our voluntary production curtailment initiative and ahead of expectations.
Our revenues, including the impact of cash settled derivatives and excluding brokered gas and marketing revenues were $58.8 million and our adjusted EBITDAX was $17.1 million for the quarter, both above analyst consensus expectations. Our per unit operating cost during the quarter were $1.20 per Mcfe at the low end of our guidance range; and cash G&A expenses were $8.2 million, below the midpoint of our guidance range.
I'm very pleased to announce that because of the improving natural gas prices, this month we began the process of returning our previously constrained wells back to managed choke production levels consistent with our type curves. As a result, we are increasing our production guidance for the third quarter to between 215 MMcfe and 220 MMcfe per day.
For the fourth quarter of this year we are now projecting our production to grow further, to between 240 MMcfe and 260 MMcfe per day. Lastly, we are again increasing our annual guidance for the year to between 225 MMcfe and 230 MMcfe per day.
At the end of the quarter and pro forma for the equity offering we completed in July of this year, we had $237 million in cash and total liquidity of $334 million due to our undrawn revolving credit facility. This liquidity positions us to fund our drilling and completion programs thereby substantially growing our production and cash flows into 2017 and beyond.
Operationally, as we previously announced, we recommenced our one rig drilling program in the Utica shale dry gas area and restarted our completion operations on our inventory of drilled but uncompleted wells in our Utica shale condensate area. We continue to be very excited by the production and pressure characteristics that we are seeing from our first super lateral well with an 18,500 foot lateral.
I'm pleased to report that the well has now produced a cumulative 1.2 billion cubic feet equivalent over the first 90 days since turning the well to sales, and most excitingly with an average pressure decline of just 45 PSI per week.
Although still too early to determine the proved reserves associated with this well, we currently believe that the well will ultimately be assigned reserves of between 1 Bcfe and 1.2 Bcfe per thousand foot of lateral or, 19.7 Bcfe to 22.2 Bcfe total. I would point out that even the low end of this range exceeds our type curve expectations adjusted per lateral footage for that area.
I'm also pleased to report that even though the operating team was inactive during much of late last year and early this year, with the recommencement of activity, we have not seen a loss of operational efficiency as the team has gotten back to work.
Additionally, as Tom will discuss further, we are now applying and even expanding upon the completion design we used on our Purple Hayes super lateral well which we hope will continue to result in wells exceeding our type curve expectation assumptions as the Purple Hayes well appears to be.
Moving forward we are continuing to design our drilling program to extend our lateral reach across all our units on our acreage position. And as a result, our current expectation is that our average lateral in 2017 will be approximately 14,000 feet which will focus predominantly in the dry gas portion of our Utica shale acreage.
As we continue to refine our plans for 2017, our current plan is to run one operated rig throughout the year. However, we are simultaneously developing an alternate plan that will result in an increased operated rig count by midyear 2017 to further accelerate our growth.
However, we remain committed to not stressing our balance sheet. So although we are doing the well planning, land work, etcetera, necessary to add a second operated rig, we will hold off on committing to this further acceleration until we have better confirmation that forward gas prices next year and into 2018 will be at acceptable levels that we can hedge appropriately.
Additionally, we are continuing to work on certain non core acreage sales out of our focus area that could potentially fund a significant portion of this further acceleration as well as blocking up our acreage position in order to focus on longer lateral's on all our operated wells. I am convinced that we are well positioned to return to a growth oriented strategy with a balance sheet to fund that strategy.
We have a clear operational story which is focused on drilling high returning wells in the current price environment with a top operating team in the basin and combined with a financial structure to support our growth plan with little to no incremental debt or revolver borrowings.
With that, I'll turn the call over to Tom.
Thanks, Ben. As Ben mentioned I'm pleased to say our operations team has gotten back to work without missing a beat given their period of inactivity late last year and earlier this year. We have now begun the process of completing our DUC inventory consisting of 20 net wells primarily in the lean condensate area of our acreage. Additionally, we have recommenced the drilling and completion of wells in the dry gas area which have an average lateral length of approximately 11,000 feet in 2016.
Since resuming operations, we have drilled three gross, or three net wells, net operated Utica shale wells and are currently moving to the fourth well in the dry gas portion of our Utica shale acreage in eastern Monroe county. In addition, we have completed seven gross, or 6.6 net wells averaging eight stages per day in the liquids rich portion of our acreage in Guernsey County, Ohio. Our frac crew is currently finishing the last two wells on a in Guernsey County where we are testing 110-foot stage spacing. The crew has completed as many as 16 stages in a day while averaging just over ten stages per day on this pad.
This week we have also begun the process of putting our first four well pad to sales and expect to bring the next five well pad into sales in early September. For the full year 2016 we now plan to spud approximately 10 to 12 wells, complete approximately 16 to 19 DUCs, and turn 12 to 15 net wells to sales.
Our first super lateral well, the Purple Hayes well, continues to perform above expectations, having now produced a cumulative amount of 1.2 Bcfe during its first 90 days while sustaining very shallow pressure declines of approximately 45 PSI per week. This leading edge well is the result of a well disciplined approach to planning by our best in class operating team which we view as one of the most sophisticated operating teams working in the basin.
As we mentioned earlier this team was able to drill this 18,700 foot lateral with one bit run in just 10.2 days with the entire well, which has a total measured depth of just over 27,000 feet, drilled in just under 18 days from surface to TD. On the completion side, the team was able to put each stage away with 1,400 pound per foot sand loading without any problem.
This optimized completion design using 150 foot stage spacing and hundred percent slick water was achievable due to the team's ability to incorporate an innovative combination of available products resulting in a unique and highly specialized completion fluid system that allowed for full placement of stages while reaping all the benefits of a slick water completion.
While it was initially unclear as to how the toe stages would treat due to sheer distance from service, or how they would contribute to production, we can now confidently state that these stages do not appear to have experienced any degradation as the fracs went well and tracer surveys show the stages are contributing.
We continue to be very excited about these early production results. As mentioned, the well is exhibiting an average weekly pressure decline of 45 pounds per week in its first 90 days. This decline is significantly less than mild and is trending towards the high to mid forecast reserve level of 1 Bcfe per thousand foot to 1.2 bcf per thousand foot lateral. Most importantly, we believe the technology as designed and techniques we have developed can be applied across our entire acreage position.
We are currently implementing some of the these ideas on our DUC inventory. Given the low price environment we are looking to assess the impact of significant increases in sand concentration as well as looking into the impact of shorter stage spacing. With the current and coming completions, we will be experimenting with sand concentrations varying from 1,800 pounds per foot to approximately 3,000 pounds per foot. The site concentration levels pumped in slick water is only possible due to the completion's fluid, design during our super lateral process.
With regard to spacing, we will be experimenting with spacing as tight as 110 feet per stage. We are excited to see the results of these approaches and hope to see substantial performance improvement using these completion designs.
Overall, I remain fairly pleased with this team and their push to innovate in order to enhance the value of our asset basin Company. I cannot be more excited to be back at work developing our world class asset. With that, I'll turn the call over to Matt.
Thanks, Tom. For the second quarter of 2016 we continue to see solid revenue generation equating to $47.1 million. Our adjusted revenue, which includes the impact of cash settled derivatives, was $58.8 million, and our adjusted EBITDAX was $17.1 million. These metrics were all higher than our internal plan driven by higher than anticipated commodity prices, slightly higher than planned production and lower operating expense.
As Ben stated, during the quarter we were impacted by a prior period adjustment associated with one of our non-op partners. This adjustment was primarily related to changes in gas shrink and Btu estimates which affected our production, pricing, and operating expenses.
This adjustment increased our production by $24 million a day for the quarter. It caused our realized price per Mcfe to drop by $0.21 consisting of a reduction in natural gas realized price of $0.24 per Mcf and an increase in NGL pricing of $0.61 per barrel. Finally, it increased our per unit operating expenses by $0.13 per Mcfe. As I walk through some of our highlights the numbers will include the impact of this adjustment.
During the quarter, we realized the price of $2.14 per Mcfe before the impact of cash settled derivatives, and $2.74 after this impact. Our natural gas differential before transportation expense was negative $0.60. While above our guidance range this was primarily due to the impact of the before mentioned estimate revision and to a lesser extent due to lower realizations in the summer M3 markets and from point sales and direct. Our firm transportation expense was $0.08 below the low end of our guidance range at $0.32.
While we have been excited to see the natural gas Benchmark prices improve over the course of the quarter, we have not seen the full impact of these moves as summer differentials have widened consistent with seasonal trends. We expect this to continue in the third quarter shoulder period. As always, our team will continue to work to move our gas to multiple markets outside of the basin in order to mitigate this impact of widened differentials and enhance our realizations.
From a firm transportation perspective, we look forward to the fourth quarter when we expect to bring online our 205 million a day capacity going into the TETCO pool. This capacity is expected to come online in October, ahead of schedule and will allow us to access the market which is consistently traded with differentials relative to NIMEX in the negative $0.10 to $0.15 range.
Turning to our oil sales. Our realized oil price during the first quarter of $36.74 per barrel implies a negative $9.47 differential to WTI. This differential was better than the low end of expectations. For the third quarter, given the strengthening and supply demand dynamics in local markets, we have tightened our guidance range to between $9.00 to $11.00 below WTI.
As we look at our NGL sales during the second quarter, we realized a $13.60 per barrel NGL price equating to 29% of WTI. This improved realization was positively impacted by the estimated revision but also enhanced by improved prices across our NGL barrel. During the quarter, NGL prices were positively impacted by the increase in crude price, by the movement of ethane and other products to export markets and due to the reduction in NGL supply growth across the country.
Of note for the third quarter we have recently agreed to sell ethane to a party with Mariner East 1 capacity. Starting this month, this agreement will impact approximately 50% of our operating ethane sales, or approximately 1,250 gallons per day and should allow us to see an uplift in pricing on the order of $0.05 to $0.10 per gallon based on current pricing.
Given this ethane agreement and the overall improvement in NGL markets, we have moved up our third quarter NGL guidance from being in the low 20% area relative to WTI, to now being in the mid 20% area or better.
Moving to operating expenses. Our operating costs excluding firm transportation, G&A and DD&A was $1.20 per Mcfe per quarter. This expense was at the low end of our guidance range when including our non operating adjustment and significantly beat our range when we exclude the impact of the revision.
This beat was largely due to across the board beats and express line items including direct LOE, salt water disposal expense and liquids transportation expense. Given these reductions, but also recognizing the significant number of lean condensate wells coming on in the quarter, we have reduced our operating expense guidance for the third quarter to be between $1.15 to $1.20 per Mcfe.
Turning to G&A. As we have stated a number of times we are managing through this commodity cycle with a critical eye toward ensuring our general administrative requirements are appropriate relevant to our activity levels. For the second quarter our cash G&A was $8.2 million which was below the midpoint of our guidance range. And included in this G&A figure is approximately $1 million associated with severance costs from our previously announced work force reduction.
We continue to strive to sequentially move our G&A lower despite our recent acceleration activity and forecast cash G&A of approximately $6 million to $7 million in the third quarter and full year cash G&A of approximately $30 million.
For the second quarter, our $24.6 million of capital expenditures consisted of $21.1 million in drilling completion capital, $2.6 million in land related capital and $0.9 million in midstream capital costs. The second quarter reduction in spending relative to guidance was primarily driven by timing adjustments to our operating activity during the quarter and is expected to be [indiscernible] in the third quarter. As such, we continue to expect our capital expenditures for the year will be consistent with our $196 million approved budget.
With regard to exploration expense, our cash exploration expense was approximately $7.5 million. This was slightly higher than planned and related primarily to the timing of some lumpy delay rental payments that hit during the quarter. In the coming third quarter, we expect this amount to drop and have set our guidance at a range of $4 million to $6 million.
From a hedging perspective, Eclipse has continued to focus on enhancing margins and protecting cash flows. We currently have 135,000 MMBtu per day of natural gas that is in place for the remainder of 2016 at a average price of $3.11 per MMBtu, equating to approximately 80% of production at the current guidance level.
Additionally, we have 1,850 barrels a day of oil hedges at an average floor price of $53.52 per barrel, and we have 52,500 gallons of propane hedged at an average price of $0.46 per gallon. Recently, we have also taken additional steps to manage the natural gas price risk associated with our 2017 and 2018 natural gas production. We have added to our natural gas hedging position by putting in place an additional 50,000 MMBtu per day of hedges. Overall in 2017 we now have 190,000 MMBtu per day natural gas hedge and an average floor price of $2.84, or 80% of the forecasted production.
For 2018 we currently have approximately 50,000 MMBtu per day with an average floor price of $2.81. We have generally used callers for three way structures for these hedges in order to maintain up side as the supply demand balance continues to improve over the coming years. From a liquidity perspective, we ended the quarter with $211 million in liquidity. This consists of $114 million in cash and $97 million availability on our revolving credit facility.
During the second quarter, we also launched a price of $37.5 million share equity offering generating proceeds of $123 million. Pro forma liquidity including these proceeds was $334 million. This liquidity puts us in a strong position to fund our 2016 and 2017 expected capital requirements and allows the Company to continue to grow cash flows and enhanced credit metrics.
To conclude my remarks, I would say the performance for the period was quite strong. We beat production expectations, achieved EBITDAX levels consistent with consensus expectations, even with a non-operated adjustment that negatively impacted our cash flows by approximately $4 million. We've beat realized pricing guidance for oil and NGLs, achieved operating expenses that were at the low end of our guidance range and improved liquidity by $123 million.
Looking at the coming quarter we have increased production guidance, improved our oil and NGL differential guidance range, lowered our OpEx per Mcf guidance range and have a fully funded plan driving strong cash flow growth through 2017.
On that note, Ben will wrap up our prepared remarks.
Thank you, Matt. We continue to believe we are well positioned with a superior asset base in the core of the premier natural gas basin in the US, and probably the world. Low prices have already taken away much of the supply growth momentum previously generated.
Given the continued decreased level of capital expenditures associated with the producers in the basin, and the fact that almost half of US natural gas supply is conventional gas, which is in terminal decline, the resilience of supply and production roll over that have started to be reflected in the government data with the weekly natural gas draws this summer significantly below the historic average, should continue to pick up steam just as we start to move to a more advantage winter environment for pricing as well as demand.
We have now seen some of the ultimate underappreciated longer term supply and demand drivers take hold in our region. Such as the corporate level approval of the shell cracker facility in the industrial petro chemical complex and the significant amount of power [indiscernible] in this summer's heat wave, attributable to a potential La Nina event. These phenomenon will continue to take hold and reward those companies with the foresight and planning to capitalize on the peaks and troughs of the cyclical commodity.
I continue to be impressed by the many accomplishments of our team and the innovative out of the box thinking that pushes the boundaries of technical feasibility on our wells with the ultimate goal of significantly changing the cost structure and our returns.
Our team's persistent focus on building the future will continue to create value over time and our belief is that the sustained success in the EMP industry requires the continual application of new technologies and the adoption of new ways of thinking. Innovation has always been at the forefront of our strategic outlook and will result in significant value creation for our stockholders. Our existing well performance along with the efficient execution of our super lateral project continues to be supportive for upward revisions and combined with further declining well costs, drive increasing value.
We believe we currently maintain the financial flexibility to drive a very robust production growth profile yet a current market valuation that allows for significant stock price appreciation. The current environment will present opportunities to grow our Company given our execution ability and low cost structure. As we manage through this commodity cycle we will continue to leverage our strong liquidity position and with our expertise and operational efficiencies, we have the ability to quickly adapt to a changing commodity price environment.
Operator, at this time, please open the phone lines for questions.
[Operator Instructions]. The first question comes from the line of Neal Dingmann with SunTrust. Please, state your question.
Good morning, guys, thanks for the details and great guidance. Say, a question looking at the slide in the deck of your slides that shows the type curve summary, based on that and now after the impact you've had on the Purple Hayes well, how do you and Tom, when you look at the plan for 2017 think about in two things, one laterals, is it always longer, is your preference if the lease is available there? And then secondly, just how you think about coming to plan next year as far as the dry gas versus, going into the Guernsey versus given the improvement in NGLs?
Sure. Good morning, Neal. To answer your first question, in our opinion, in this particular play, longer is almost always better. And that's what we are attempting to prove with the Purple Hayes well. In our dry gas acreage, it is quite a bit deeper and higher pressured so our lateral lengths will be a little bit shorter than they would be in condensate. But sales substantially longer than anyone else in the industry is, at this point, even attempting to do.
So as we move into next year, given where current gas prices and current oil prices are, our focus remains on the dry gas portion of our acreage, and we are working daily to block up acreage, to extend lateral lengths on our dry gas acreage as well. As we look forward to next year, current plans have us averaging about 14,000 foot laterals, almost all of which is in the dry gas portion. We do have two super lateral condensate wells planned in mid year, but at this point, and they are a little over 19,000 foot laterals. But they're also depending on where oil price is at the time.
So if oil is still in the 40s, then we probably would hold off drilling those and just stick to our dry gas portion of the acreage. Incidentally we also plan at the end of this year to test some more Marcellus drilling on our dry gas acreage where we have a pad where we will drill three Utica wells and two Marcellus wells. And even the Marcellus wells will be a bit longer than normal; one of them at 8,000 foot and one of them at 10,000 foot.
Perfect. And then, lastly, one quick follow-up. On the partner adjustment, maybe a question for Matt, is that maybe a one timer? You don't see any of that going forward, any more of that?
That's right. Effectively related about 15 months of history and I think we got it sorted with the partner there and we should be good going forward.
Great. Thanks, guys. Great update.
Our next question comes from the line of Holly Stewart, with Scotia Howard Weil. Please, state your question.
Good morning, gentlemen. A couple quick ones here. Ben, I think you mentioned within the release actively pursuing several initiatives to further expand growth? I was just hoping you could give us a little more color there?
Sure, Holly. I mean it's difficult to go into too much detail. But we are looking at some potential divestment of some noncore acreage, which is an area of our acreage position where we aren't really focused and really can't extend the lateral lengths as long as we'd want to.
If that potentially closes, then that would provide some significant additional funding which would allow us to further accelerate drilling next year.
At the same time, we are equally as focused on adding to our position, really in both areas but more so right now in the dry gas area, so that we can continue to drill longer and longer laterals. It really is in both sense. I mean we're looking at ways to add acreage even if it's through a farm in drill-to-urn type structures with the real focus on how do we do longer, longer laterals where we see better and better economics.
Gotcha. Great. And then for 2017, you've provided the I guess initial look at targeted growth. Any sort of brackets around D&C you can put out there for us?
Sure. At this point we are not changing our guidance for CapEx next year of $200 million to $225 million, which is essentially just the one rig program.
As we said briefly in the release, we would very much like to be going to two rigs mid next year however, I think there's two triggers for that to happen. One, the financing of that rig so that we don't have to draw a revolver and burden the balance sheet, which would require either a non core acreage sale or some type of other joint venture.
And at this point, we aren't really looking at the traditional joint venture type capital. We're really more focused on the noncore acreage sale. But the other trigger to bring in the second rig is really where do we see gas prices predominantly in 2018, and where can we hedge out that production at the time we bring on that rig. As you probably know, the strip on the gas price has moved up considerably in 2017. However, 2018 has remained persistently flat. So we continue to watch that.
And it's really a decision that we'll make as we get into the winter months and one, make sure that we do have a normal winter and that we're seeing strip prices in 2018 at levels that we're comfortable hedging.
Great. And then maybe just one more, if I could. We're starting to see more companies extracting ethane. I know you mentioned a new contract that you guys have just entered into and I seem to recall that your previous contract you were extracting at least a portion of ethane and you had the option to recover more if pricing warranted.
So can you just let us know where ethane volumes stand? And then, I guess at what pricing point would you kind of consider for covering it at higher levels?
I think contractually we're required to recover about 30% of our ethane. And so I think pricing where it is right now, we wouldn't want to go beyond that because the Btu uplift still has more value than even the incremental dollars we're receiving through the Mariner One Agreement.
From a volumes perspective, we're at about 2,500 gallons a day of NGLs. That will move up, or, of ethane. That will move up as we get these DUCs on line. And basically the contract we've entered into allows us to move about half of that volume into Mariner One based on kind of a quarterly look at what we expect our volumes to be. I haven't run the math on where Btu values intersect with ethane so I don't have it off the top of my head but I can get back to you on that one if that helps.
Okay. Yes. That's great. Thanks, guys.
Our next question comes from Kyle Rhodes, with RBC. Please, state your question.
Hey, good morning, guys I just had a couple quick follow-ups. Just on the potential of sale some of your more scattered acreage blocks, any rough quantification of your acreage that you would place in that bucket?
Well, with a particular potential transaction that we're working on, it's on the record of 8,000 to 10,000 acres, so not a huge piece of our acreage position.
Got it. Okay. That's helpful. And then just circling back on the Mariner East kind of ethane volume share they're getting on there, what's the duration of that agreement, and can you guys kind of leg into more volumes as you complete some of these DUCs in the back half of the year?
The duration is really, ten year plus. The agreement kind of shifts a bit once the shell [indiscernible] comes on because we've committed ethane there. So obviously, you know, the priority is that we want to and have to meet the demands of that [indiscernible] facility first.
But from a near term perspective, I think in answering your second question, the answer is, yes, we make an election so that on a quarterly basis so that we can change those volumes as the DUCs come on, or to the extent NGL or oil prices recover and more of it can go that way, we can also increase that as well.
Great. And then just maybe I know it's a ways off, but you mentioned 2018 gas prices kind of being important inflection point in terms of deciding on the second rig. Any particular price you want to kind of throw out there in terms of what you need to see in order to be able to hedge out in 2018?
Sure. I mean simplistically we're looking for gas prices to be in the threes. With right now the [indiscernible] strip 2018 it's just below three. We'd like to be able to [indiscernible] it more where the floor is at three. That's kind of what we're looking for.
Thanks, guys. I appreciate it.
Our next question comes from the line of John Nelson, with Goldman Sachs. Please, state your question.
Good morning and congratulations on the update. I'm just curious on the comment that next year's program is going to be all 14,000 kind of average foot lateral length. Do you think that will have a significant impact in terms of kind of lengthening your cycle times and getting wells to sale to take advantage of some of next year's price strength? If you can maybe comment there?
Sure. No. It really doesn't. When you look at the Purple Hayes well which is almost 19,000 foot long, we drilled the entire thing in under 18 days. Where we're drilling now, this is some of the beauty of why the long lateral has made sense, is once we're in a well bore, in this particular play anyway, it's not uncommon we'll do 3,000 sometimes even 4,000 foot in a day. So your incremental time and cost is cheaper and cheaper every foot you do.
So there's not an appreciable increase in our cycle times. Combined with that, as we move to completions, we're, obviously, completing more stages with longer wells. We've moved almost exclusively to zipper fracking where this week we had a day where we fracked 16 stages in one day and are consistently doing ten stages a day.
So that's part of why our cycle times really won't be noticed as increasing by the public, and it really honestly is due to the unbelievable operational performance that both the drilling and completion guys are doing to do 16 stages in a day on a single pad is very, very remarkable.
That's really helpful. And then my second question, in the past you talked about the amount of acreage that still needs to be kind of HBP'd or have delay rental payments. If we can get an update on where that is and if the potential divestiture should meaningfully move those numbers?
Sure. Now, the second part of your question is the potential divestiture doesn't meaningfully move it. Some of it does but not in a huge way. We are continuing our program to amend leases to extend out terms using delay rentals. That program is ongoing. It's kind of a routine thing where in any one week we'll pick up anywhere from 100 to 500 acres remaining. But there hasn't been an appreciable change or update on that project. It's an ongoing thing and something we do every day.
Great. I'll leave it there. Thanks.
Our next question comes from David Deckelbaum, at KeyBanc Capital Markets. Please, state your question.
Good morning Ben, Matt, and Tom.
I think you guys laid out a lot of scenarios in having a second [indiscernible] in 2017, so understand that upside there. But also just trying to understand more the EOR estimates for the Purple Hayes, the 1 to 1.2 Bcf per thousand, obviously, exceeds your type curve guidance for your other condensate when there's a .7 to .9 Bcf. Are you attributing this mostly to the completion design of the proppant per stage and stage spacing? And, would it then be logical to assume that as you apply this on your DUCs that we might see that type curve at least per thousand foot walk up across the condensate window?
Yes. We really attribute it all to the changing completion design using 100% slick water. Interestingly, the Purple Hayes well, although it appears over our type curve didn't really use high amounts of sand concentration compared to what we've historically used.
The important part was being able to go to a 100% slick water on a 18,000-foot lateral and place proppant out at the end of that lateral to the TOE stages, really required us to come up with some very unique liquids that allowed us to move that proppant and still stay using slick water which we think is the biggest determinant in the step change of well performance.
As we move forward to completing the DUC wells, what we have found is those new completion fluids allow us to move greater and greater amounts of sand into the well bore especially doing shorter laterals on wells that we drilled a couple years ago.
So we're now in the process of really testing greater and greater amounts of sand using all slick water that we can do with this new completion fluid. And to answer your question, yes, I mean the hope is that the Purple Hayes well is not a one off deal and that we are on a track to increase our EUR expectations in the condensate area.
I would put out we didn't really focus on this in the release, but we fully intend to continue that same increase in proppant and 100% slick water in our dry gas wells as we drill and complete those throughout the year as well.
So really the next focus is greater and greater intensity of fracture completions, given that we've already proven we can do the longer laterals. And with service costs being what they are it's a great time to test larger and larger amounts of proppant.
Thanks, Ben. You actually answered my second question there on applying it to the dry gas wells. I appreciate that color. That's all for me, guys.
Our next question comes from the line of Ron Mills, with Johnson Rice & Company. Please, state your question.
Good morning, Ben. You talked about the average lateral length of about 14,000 foot this year and continuing to work on acreage slots. How does your acreage lay-out look right now in terms of allowing for that full 14,000 foot laterals? Did you have to effect some swaps? Just curious if you have a percentage of how much acreage have longer laterals versus maybe shorter laterals?
The drilling program for next year averages just about 14,000 feet, those units and wells are pretty much already laid out. If it takes us six to eight months to put together a unit, in Appalachia which is very common, so that part of our drilling program is pretty much solidified. We are constantly working on small acreage slots within those units, but that's very routine.
When I talk about blocking up our acreage to extend lateral lengths it's really with an eye towards going longer than that. Where the dry gas areas, we would much rather be routinely doing 15,000 to 16,000 foot laterals. Actually, have a couple planned that are even longer than that. The 14,000 foot is, you know, a mix of different lateral lengths, but it's really what we can do pretty much on our acreage position right now.
The two 19,000 foot super laterals that you talked about, those would just, I want to make sure I heard correct. Those would be in the condensate areas and those would be dependent on oil prices, correct?
That's correct. The result of the Purple Hayes well was phenomenal. Really, the intent of that project is as oil prices rebound back into the 50s, how can we make that area, the Utica shale, work in our cost structure when most of our peers have pretty much moved out of the area? We really want oil prices to be at least in the 50s until we really start al locating a lot of capital there. And most of our acreage in the condensate area is HPP'd from conventional production.
Okay. Great. And then just for you, or for Tom, but on the completion design changes, you know, 110 versus 150 feet in terms of frac stages and proppant levels between kind of 1,800 to 3,000 pounds per foot. A little bit more color there? What are the primary impact that those changes have on costs whether it be total well or on a per stage basis?
Sure. So simplistically, whether we're doing a tighter stage at 2,400 pounds or 150 foot stage at 3,000 pounds, your incremental cost difference versus our base case assumption, which was 200 foot stages at roughly 1,400 pounds is only about $3,000 a stage.
And right now with the speed at which we are drilling and completing, we've actually been able to make up those costs and come in under our AFE costs consistently. So that is not increasing our well costs because of our operational efficiencies, and because the incremental cost is so negligible.
And you get the benefit of doing the testing in a lower cost environment, so you kind of hit the ground running even though if overall activity goes up and starts to reverse the service cost deflation. Was that the concept?
Yes. That's essentially the concept. I will say we have continued to extend out the period of time at which we have really locked in our completion costs, which we're basically extending that contract out another 18 months. Which essentially locks in our completion costs. It does provide for some small cost increase, but it is very minor over that 18 month period. So it's something we continued to work on constantly.
I will say the other cost saving opportunity for us is that the rig that we are currently running, that we're very happy with from a performance standpoint is still at a day rate that is above market prices and that contract will roll off in the third quarter of next year. Which, we'll probably start to look to renegotiate that contract relatively soon, as well as if we are ultimately able to bring in the second rig at current day rates, that would knock about $200,000 off of every well we drill. So that's kind of our next move to bring the cost down.
Great. And the service contracts, is that the rig, obviously, rate hasn't changed so that's all the other services and materials?
That contract is really just for pumping services. But it does include the acquisition of proppant.
Perfect. Everything else has been asked. Thank you so much.
Our next question comes from Gabe Daoud, with JPMorgan. Please, state your question.
Hey, good morning guys. Could you maybe just talk a little bit about capital flexibility and what the strategy would be should gas prices retreat from the move up to the $2.85 to the $3.00 kind of level? Just thinking about what it would take to initiate voluntary volume curtailments again?
Sure, Gabe. Well, first I think we demonstrated in the last downturn that we won't hesitate to significantly curtail, if not cease D&C operations in order to maintain our balance sheet. With the rate contract that I mentioned expiring at the end of next year or third quarter of next year, that actually is becoming easier and easier to do every day as that, essentially rig termination costs, gets lower and lower and lower. So if prices plummeted next year rather than park our rig and pay for it to be parked and pay stand by costs, we're actually getting to the point where we can just terminate it and let the rig go and pay a small fee and be done with it.
At what point we would do that is hard to say. Especially since next year we're going to grow our production by at least 30%. Personally, I think that's very much on the low end, and we've had about 80% of that. So next year cash flows are very, very predictable to us and wouldn't really be a lot of reason that we wouldn't move forward with that plan given that we've hedged it all out. Obviously, that's not true in 2018. Our hedges in 2018 are very much a work in progress but something you're going to see us continue to add to in the environment that we think we're in for the next three to five years.
Perfect. Thanks, Ben. And one quick follow-up, the potential second rig, would you assume that second rig is added to the dry gas area or given the improvements with completions in the condensate and wet areas do you think the rig goes there potentially?
I think unless you see oil move soundly into the 50s we would look at the second rig in to dry gas as well as some up hold Marcellus drilling.
Gotcha and maybe one quick one. Any thoughts on just the growth potential under a one and a half rig program in 2017 assuming you do add that second in the middle of the year?
Sure. If we don't add the second rig until mid next year, then the production growth doesn't change that much in 2017 because it generally takes six months from the time we start until we go to sales using pad drilling. What it really does is then creates a growth profile in 2018 that is very similar to what 2017's was.
Makes sense. Thanks Ben. Thanks guys.
And our next question comes from David Beard, with Coker and Palmer Investment Securities. Please, state your question.
Good morning, gentlemen. Most of my questions have been answered but just a follow-up on your 14,000 foot lateral. Would you still assume that's around the 1.8 to 2.0 Bcf per thousand feet? And is that figure based on the 150 foot spacing? And may we see some upside if you get tighter spacing and 100% slick water? Thanks.
You're referring to the dry gas areas.
Correct. Correct. Just from the slide.
To be honest with you, we don't have data yet on what we think the potential uplift is. Using the 100% slick water and, you know, greater amounts of proppant. The last pad that we did turn to sales which did use slick water last year has been off and on because of our production curtailment. As it has slowed, it is right on top of our type curve expectations and we're very happy with it but we'd like to see how it produces over time on a unconstrained basis.
As we move forward into fracking our first pad in the dry gas area, which will start in the next month, we do intend to increase proppant, tighten stages do more slick water, but it will be some time until we have enough data to know whether that increases the type curve or not. But that's absolutely the hope.
Okay. Good. Thank you. Appreciate the color.
Our last question comes from the line of Matt Sorrenson, with Seaport Global. Please, state your question.
Hi. Good morning. Thanks for squeezing me in. Given the improvement in 2017 commodity prices would you guys please discuss your outlook on 2017 differentials? And then, with additional dry gas volumes slated for 2017, what type of improvement could we see in unit operating expenses? Thanks.
On the differential front, the biggest driver of differentials for us in 2017 will be shifting a lot of our capacity into the new TECO pool capacity that I mentioned and so a lot of production will be going there. As I mentioned, that pool has been trading in the 10 to 15 set under area and so when you factor in some amount of Btu uplift and the likes, you know, I wouldn't be surprised if we saw 17, you know, natural gas basis in that negative $0.15, maybe better, ZIP code.
Now, obviously, basis markets are pretty volatile so we might look at it three months from now and the world will have changed, but we feel pretty good that basis totals have tightened up as we look at 2017 and bring that capacity online.
You know, from an OpEX perspective, I think you're going to have the condensate DUC wells come on, or lean condensate DUC wells come on. Those tend to have a little higher OpEX associated with them relative to dry gas. That said, the activity will be dry gas heavy, especially as you move into the second half of the year and you have a little less activity in terms of DUC wells coming on.
So I would say a safe bet right now is in or around the guidance range where we have 16 at this point. But that could certainly be tighter just depending on the makeup in the mix as we actually get into the program.
Great. Thanks very much.
And at this time, there are no further questions so I will turn it back to management for closing remarks.
Thank you. I'd like to thank everybody for participating and we hope to see several of you at the conference in Denver. Thank you.
This concludes today's conference. Thank you for your participation. You may disconnect your lines at this time. Thank you.
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