Vince White - VP, Communications and IR John Richels - President and CEO Dave Hager - COO Tom Mitchell - EVP and CFO Darryl Smette - EVP, Marketing, Facilities, Pipeline and Supply Chain.
David Hickman - Hickman Energy Advisor Doug Leggate - Bank of America Merrill Lynch Brian Singer - Goldman Sachs Arun Jayaram - Credit Suisse Subash Chandra - Jefferies.
Welcome to Devon Energy’s Second Quarter 2014 Earnings Conference Call. At this time all participants are in a listen-only mode. After the prepared remarks we will conduct a question-and-answer session. The call is being recorded. At this time, I’d like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations.
Sir, you may begin..
Thank you and welcome everyone to Devon’s second quarter earnings call and webcast. Before we get started, I want to make sure that everyone is aware that we have prepared a handful of slides to supplement today’s script. These are integrated with today’s webcast and they’re also available for download in PDF form on Devon’s home page devonenergy.com.
For those that are not participating via webcast, we’ll make sure we refer to slide numbers during our prepared remarks so that you can follow along.
Today’s call will follow our usual format and I a few preliminary items to cover, then I’ll turn the call over to our president and CEO, John Richels for this comments, following John, Dave Hager, our chief operating officer will provide an operations update and we’ll wrap up the prepared commentary with a financial review by our CFO, Tom Mitchell.
After our financial discussion, we’ll have a Q&A session and we’ll conclude the call after about an hour and of course a replay will be available later today on our Web site. The investor relations team will also be available this afternoon should you have any follow-up questions.
On the call today, we’re going to update some of our forward looking information. In addition to the updates that we are providing in the call, we will file a Form 8-K later today that will have details of our updated 2014 estimates. A copy of this updated 8-K will be available within the Investor Relations section of the Devon Web site as well.
The guidance we provide today includes plans, forecast, expectations and estimates which are forward-looking statements under U.S. Securities Law. These are of course subject to a number of assumptions, risk and uncertainties many of which are beyond the Company’s control.
These statements are not guarantees of future performance and we’d invite you to see the discussion of risk factors relating to these estimates and our Form 10-K. Also in today’s call, we’ll reference certain non-GAAP performance measures.
When we use these measures we are required to provide specific related disclosures, those disclosures can be found on Devon’s website. As many of you know I am retiring from Devon at the end of this week. I can honestly say that being a part of this organization for the last 21 years has been both a pleasure and a privilege.
I am truly grateful to all my friends at Devon and in the investment community and the industry for making my time here so rewarding. So thank you. At this point I’ll turn the call over to John Richels. John..
Thank you Vince and on behalf of the Company and many people you have positively impacted over your career. I just want to take this opportunity to thank you. You’ve done a terrific job through the years and you have been a great friend and we wish both you and Marty a very happy and healthy retirement.
Now as many of you know with Vince’s retirement, Howard Thill has joined our team as Senior Vice President of Communications Investor Relations. Howard has a long history in the business with over 30 years of experience the last 12 and much the same role at Marathon Oil and previously at Phillips Petroleum.
We’re very fortunate to have an individual of Howard’s experience join our team and we welcome Howard to Devon. I am sure that many of you will have the opportunity to meet with Howard over the coming months. So let’s move to the results of the quarter.
The second quarter was another outstanding one for Devon both operationally and financially as we continued to successfully execute on our strategic plan. As we point out on Slide 3, during the quarter we announced the sale of our non-core U.S. assets the final piece of our portfolio transformation.
Since announcing this planned transformation just nine months ago we have taken three very significant steps to reconfigure our portfolio, the accretive Eagle Ford acquisition, the unique and innovative EnLink transaction and the sale of our non-core properties at very attractive prices.
Also during this time our drilling program has delivered impressive oil production growth through our focus on our reconfigured portfolio. This oil focused effort helped to deliver a 47% increase in cash flow this quarter compared to last year’s second quarter.
And during the period we also completed number of major projects that we’ll discuss in more detail during the call. So let’s take a look at some of these highlights in a bit more detail.
Looking at Slide 4, in the second quarter we achieved year-over-year oil production growth of 34% from our go forward asset base, reaching an average daily rate of 205,000 barrels per day. This growth was driven entirely by light oil production from our retained U.S. assets which increased an impressive 79% compared to the second quarter of 2013.
This dramatic increase in U.S. oil productions largely attributable to growth from our world class operations in the Permian basin and in the Eagle Ford.
With the aggressive transformation of our North American on shore portfolio, total liquids production is expected to approach 60% of Devon’s go forward production by year-end, and that’s up from just over 30% a few years ago.
As shown on Slide 5, our focus on high margin oil development increased our companywide oil revenue 42% in the second quarter compared to the previous year and accounted for more than 60% of our total upstream revenue.
This strong revenue growth combined with our low cost structure has expanded our pre-tax cash margin per barrel by 40% year-over-year. As shown on Slide 6, as I mentioned earlier, we announced the $2.3 billion sale of our non-core oil and gas properties in the U.S. during the second quarter.
This transaction valued these gas weighted assets at approximately seven times EBITDA, significantly above our current trading multiple thereby making it immediately accretive to Devon shareholders.
Combined with the sale of our Canadian conventional gas business earlier in the year, which has also had about seven times EBITDA, pre-tax proceeds from our non-core asset divestiture program totaled more than $5 billion. We are applying these proceeds to strengthen our balance sheet by reducing the debt taken on to fund our Eagle Ford acquisition.
This portfolio repositioning provides Devon all the necessary attributes to deliver superior per share growth.
Our go forwards assets are generating excellent full cycle returns, we have a strong investment grade balance sheet and we have a deep inventory of highly economic low risk development projects in some of the most attractive basins in North America.
As you can see on Slide 7, this formidable and balanced portfolio consists of three world-class oil development plays in the Permian Basin, the Eagle Ford and the Canadian oil sands and two of the best liquids-rich gas areas in the U.S., the Barnett Shale which is nearly 30% liquids production and the Anadarko Basin which is about 45% liquids.
We also have two emerging oil plays which could further bolster the depth of our portfolio and we have a majority ownership in EnLink Midstream, one of the premier midstream companies in North America.
Turning to Slide 8, with the first six months of 2014 results now in hand, our retained asset portfolio remains on track to deliver companywide oil production growth of more than 30% year-over-year. This exceptional oil growth rate is driven entirely by the 70% plus increase we expect in U.S. wide oil production.
This should drive about 10% top-line production growth on a 6:1 energy equivalency basis. And on a value or price equivalency basis, applying a more realistic oil to natural gas price ratio of 20:1, expected top-line production growth in 2014 will be approximately 20%.
Moving to Slide 9, I'll remind you that about 80% of our 2014 E&P capital budget is focused on our core and emerging oil development opportunities which will continue to drive our oil production growth in the second half of 2014 as well as next year.
As you can see on the table to the right of that slide, year-to-date, we have spent just under half of our 2014 capital budget. With large high quality acreage positions in each of our core assets, we're positioned with a deep inventory of repeatable investment opportunities.
In fact as we discussed on our call last quarter, one of the most exciting operational developments over the past several months has been the significant expansion of our drilling inventory and our resource potential in the five margin core areas.
Led by the tremendous results that we are seeing in the Delaware Basin, our gross risk undrilled inventory has now increased by more than 5,000 locations year-to-date.
These 5,000 plus locations have been rigorously risked based on historical well performance, in-depth technical evaluations and disciplined economic expectations based on the current price and cost environment just to mention a few.
As we continue to de-risk and develop the opportunities within our portfolio, we fully expect our inventory to further increase overtime. In fact with the technical work that we have done over the last quarter, we have increasing confidence that we can materially grow this inventory in the near future and Dave will speak to this in more detail later.
Not only do we have a very large resource base but we also have the financial capacity to efficiently convert this resource into production and cash flow. Our balance sheet's in terrific shape and our operating cash flow continues to accelerate, thanks to our rapid oil growth, driving margins higher.
And don’t forget that another potential source of cash for Devon is the ability to dropdown additional midstream assets to EnLink. As seen on slides 10 and 11, two potential dropdown candidates are the access pipeline in the Canadian oil sands and the Victoria Express Pipeline in the Eagle Ford, both of which were recently completed.
These strategically located assets have exposure to two of the fastest growing oil plays in North America. While no decision has been made, these high quality pipelines could be dropped into EnLink within the next year or two.
Given the visibility of our significant cash inflows, coupled with a high margin asset base ready for development, we expect to accelerate drilling activity in 2015 across several of our core and emerging plays.
As you can see on Slide 12, Devon is positioned to deliver organic oil production growth in excess of 20% in 2015 while delivering a healthy topline production growth in the mid-single digits. The Eagle Ford and the Delaware Basin will once again lead our oil production growth in the U.S.
and we will also see significant oil growth from our Jackfish 3 project in Canada where we recently started steam injection.
In summary we’re very pleased with the execution and outcome of the transformative steps that we took over a relatively short period of time to high grade our portfolio and meaningfully improve our growth trajectory and margins.
When you combine the growth potential of our top tier oil development projects with our high quality natural gas optionality, we’re very well positioned for competitive growth for years to come.
And as we execute on our growth plans Devon shareholders will continue to benefit from improving margins, higher cash flows and further value recognition through EnLink. And with that I’ll turn the call over to Dave Hager for a more detailed operations review.
Dave?.
Thank you John. As John mentioned our solid execution in the quarter resulted in strong oil production growth driving an impressive increase in our operating cash flow.
We are laser focused on the key drivers of outstanding operational performance, including driving down drilling times, optimized conclusion designs and very efficient production operations. Continuous improvement in each of these areas and others will provide incremental value in each of our operating areas.
Now let’s take a closer look at some of Devon’s key operating highlights in more detail. In the Permian basin we increased production 25% compared to the same quarter last year to 95,000 BOE per day. The solid execution of our development programs in the Permian place is firmly on track to grow 2014 production by 20% compared to 2013.
Importantly light oil production accounts for nearly 60% of our total Permian volumes. Shown in the green outline on Slide 13, is the Bone Spring play in Delaware Basin, a key driver of our Permian oil growth.
In the second quarter we brought 22 new Bone Spring wells online, with average 30 day IP rates of 660 BOE per day, once again exceeding our pre-drill expectations. At an average cost of just over 6 million per well our Bone Spring program is delivering some of the best returns in our portfolio.
We also have an ongoing Delaware Sands program that is beating expectations. In the second quarter we commenced production on two high-rate oil wells targeting the Delaware Sands Lea County, New Mexico. Initial 30-day production from each of these two wells averaged about 1,000 BOE per day, 70% of which was light oil.
As we discussed last quarter the tremendous results from our Delaware Basin drilling programs coupled with an ongoing reservoir characterization work allowed us to substantially increase our rest undrilled inventory.
The stack pay nature of our position in Delaware Basin provides us with exposure not only to the Bone Spring and Delaware Sands but also the Leonard Shale, Wolfcamp and several other oil zones. In aggregate our multi-zone potential and the Delaware Basin provides us with exposure to more than 5,000 (risk) [ph] undrilled locations.
Turning your attention to Slide 14, I want to be clear. This inventory of 5,000 plus locations is not simply acreage divided by an arbitrary well spacing. We screen these locations based on multi-variant analysis that takes into account geologic, geophysical, completion and production data that characterize and predict reservoir performance.
This disciplined methodology is utilized across our entire portfolio including the Delaware Basin to identify and quantify undrilled inventory. Slide 15, provides a summary of the risking applied to each of our perspective zones in the Delaware Basin.
In the second column our technical teams have identified net perspective acres in each formation in the Delaware Basin. Next, the multi-variant analysis I just described was performed by our technical teams which risked these perspective acres by as much as 50%. Now there is insufficient data to do a multi-variant analysis on down spacing.
So you can see we conservatively assumed only four to five wells per drillable section in each formation. Given that we believe there is meaningful upside to our inventory.
For example we’re currently implanting a program in the Delaware Basin to utilize a much larger and more focused frac design, deliver a more complex fracturing network closer to the well bore. We believe these larger, more complex frac designs will more effectively drain the reservoir, increase recovery factors and further enhance rate return.
In conjunction with these larger more complex focused fracs we are evaluating the concept of a staggered lateral development scheme that can further tighten well spacing across our entire prospective formations in the Delaware Basin and thus could significantly increase our risk undrilled inventory.
We will continue to update you on our progress in the coming quarters. Converting this massive and growing opportunity in the Delaware Basin into production and cash flow, is a top priority for us.
While not finalized, our preliminary plan is to increase our operated rig count from the 12 currently running in the Delaware to as many as 20 by the end of 2015. We plan to ramp the activity in an orderly fashion, as we secured gathering and processing capacity, high quality rigs, completion services and manpower to support the higher rig count.
This increased investment in the Delaware Basin will allow us to continue aggressively developing our highly profitable Bone Spring inventory and accelerate the development and appraisal of our Delaware sands, Leonard Shale and Wolfcamp inventories.
This sets up the prolific Delaware Basin position for significant high margin growth in 2015 and for years to come. Shifting to the Midland Basin, we delivered another quarter of strong results from our oil development program in a Southern Midland Wolfcamp shale.
We increased average net production in this play to 12,000 Boe per day, representing significant year-over-year increase of 9,000 Boe per day. In a Northern Midland Wolfcamp trend, we start our first horizontal well in Martin County, targeting the Wolfcamp B formation in the third quarter.
We have approximately 14,000 net acres in a prolific Martin County area, prospective to multiple Wolfcamp zones. In aggregate, we have identified about 200 undrilled locations in the Northern Midland Wolfcamp trend and this is an area likely to see increased activity as we head into 2015.
Shifting to the Eagle Ford on Slide 16, while we have wholly-owned these assets for a handful of months, we could not be more pleased with the performance we have seen from this world-class asset. And we have already identified several promising opportunities that can further enhance well economics and boost our drilling inventory.
I will speak to this in more detail shortly but let’s begin with a review of the second quarter results. During the quarter, we have 17 rigs running across our Eagle Ford position with the majority focus on developing our DeWitt County acreage in the economic heart of this top tier oil play.
We brought 60 new Eagle Ford wells online with average 30 day IP ratio, approaching 1,200 Boe per day. These high impact wells drove our average Q2 production in the Eagle Ford to 65,000 Boe per day, in line with the guidance range we had provided last quarter.
Notably, we achieved a strong growth in spite of production interruptions primarily related to third-party gathering constraints in DeWitt County. In aggregate, these gathering constraints reduced production by about 8,000 Boe per day in the quarter.
Even with these infrastructure limitations, we were able to bring approximately 30 wells online around mid-quarter that helped accelerate our average net production in June to 73,000 Boe per day. This ramp up in June represents an impressive increase of nearly 50% compared to the first quarter exit rate.
It is also worth mentioning that our Eagle Ford production is also delivering the highest pre-tax cash operating margin of any asset in our portfolio at around $60 per Boe.
Looking ahead to the second half of the year, our drilling and completion programs in Eagle Ford remain on schedule, keeping us on track to deliver outstanding production growth rates. As we have said before, this production can be somewhat lumpy due to the timing of pad drilling and third-party and midstream infrastructure.
At June 30th, we had 108 drilled wells not yet producing. We expect this inventory to continue to trend downward over the coming months as the number pads are scheduled for tie-in and a necessary transportation system improvements are completed in DeWitt County.
As a result, for the remaining six months of 2014, we are forecasting our net Eagle Ford production to average between 80,000 and 85,000 Boe per day.
We expect both the third and fourth quarter to generate solid sequential quarter production growth with volume growth weighted more toward the fourth quarter due to the timing of pad tie-ins that I just mentioned.
Overall, the second half outlook, keeps us on pace to deliver on our previously announced guidance of 70,000 to 80,000 Boe per day for 10 months of ownership this year. as I touched on earlier, we are also excited about a number of potential upside opportunities we have identified across our position in Eagle Ford.
In our development activity in DeWitt County, we are currently closely working with our partner BHP to enhance various aspects of our well completions as well as areas on the production operations side of the business.
While it's premature to discuss any specific details the technical teams have identified opportunities to optimize completion designs that could increase well recoveries and at the same time reduce well costs. The teams have also identified potential opportunities to improve the rates of return to optimize choke management.
As we continue to pursue these promising initiatives we will continue to update you on our progress. Moving to Slide 17, another leg of upside is in Lavaca County. In the second quarter we tied in our first operated well in Lavaca County targeting the lower Eagle Ford formation.
As seen on the blue on the map the initial 24 hour production from the Ronyn 1H was approximately 1,600 Boe per day, of which 70% was light oil. Combined with announced well by industry represented in gray lower Eagle Ford results to date in Lavaca County have exceeded our initial expectations.
Turning your attention to Slide 18, perhaps one of our more exciting potential upside opportunities is in the upper Eagle Ford. As shown by the size of Parkman, the majority of our DeWitt and Lavaca County acreage is highly perspective for this emerging play.
This is further supported by the encouraging industry results in Lavaca County seen in gray on the map.
It is worth noting that these Lavaca County wells results are not in the thickest part of the upper Eagle Ford, which as you can see from the map bodes well for the prospects of our DeWitt County acreage where the upper Eagle Ford net pay is the thickest.
We have just filed our first operated upper Eagle Ford well the Medina 2H on 100% working interest acreage in Northeast DeWitt County. This can be seen in blue on the map. This is the first of a handful of tasks planned this year.
If the upper Eagle Ford formation is commercially successful this could expand Devon's resource and further deepen our drilling inventory.
On Slide 19, at our Jackfish thermal oil projects in Northeastern Alberta gross production from our Jackfish 1 and Jackfish 2 projects increased 3% year-over-year to a combined average of 60,000 barrels of oil per day or 52,000 barrels per day after royalties.
Further enhancing results this significant improvement in Western Canadian slug benchmark pricing increased price realizations at Jackfish by 22% compared to the year ago quarter to $65.88. At Jackfish 1 gross production averaged 36,000 barrels per day or 29,000 barrels per day net of royalties in the second quarter.
The success of our ongoing efforts to improve our steam oil ratio once again resulted in gross production exceeding the facilities main pipe capacity of 35,000 barrels per day. In the third quarter we will bring the Jackfish 1 plant down for a schedule two week maintenance turnaround beginning in September.
Accordingly this maintenance downtime and subsequent ramp up will reduce Jackfish 1 production by 5,000 to 10,000 barrels per day in the third quarter. Keep in mind this has been built into our third quarter and full year production guidance.
At Jackfish 3 we began steaming on July 13 and expect a steady ramp up of production over the next 18 months to a sustained rate of 35,000 barrels a day. Jackfish 3 will provide multi-year oil production growth beginning in 2015 with net oil production from our Jackfish complex expected to be between 62,000 and 67,000 barrels per day.
This represents production growth of about 30% compared to 2014. Furthermore as seen on Slide 20, the completion of Jackfish 3 will begin an era of free cash flow from our Jackfish complex with the potential to generate around $1 billion annually for many years. Even after accounting for maintenance capital requirements.
Shifting now to the Anadarko Basin Western Oklahoma for our operations continued to deliver great results. In the second quarter we have once again set a production record reaching 93,000 Boe per day.
With drilling focused on our most liquid rich acreage oil and NGL production increased 26% year-over-year and is now about 45% of production in the Anadarko Basin. The Cana-Woodford play was the most significant contributor to our strong second quarter production growth in the Anadarko Basin.
This growth was driven by the strong performance of several new well pads brought on line that employed our new redesign completions as well as rejuvenated performance from existing wells as a result of our ongoing asset treatment program. Slide 21, shows the meaningful increase in sand per well along with more frac stages and tighter perp clusters.
This new frac design was utilized on the 20 Cana-Woodford well we brought on line and the liquids rich core play during the second quarter. Initial 30 day raise from these wells averaged 1,250 Boe per day including 700 barrels of liquids per day exceeding our type curve by more than 35%.
These are among the most productive wells ever drilled in Cana with average EURs trending in excess of a 1.5 million equivalent barrels per well. As you can see on Slide 22, for the 20 wells were brought online in Q2, the redesigned completions dramatically enhanced IPs, boosted EURs by more than 15% and with well cost essentially flat.
This translates into strong rates of return that are competitive with many U.S. oil plays. Our asset team at Cana have also done some outstanding work to revitalize production from existing wells with asset treatments. We have now treated nearly 200 operated and non-operated Cana wells and results have been exceptional.
In most cases, the inexpensive procedure around $250,000 per job, took production per well from about a 1 million cubic feet equivalent per day, up to 2 million a day or more. As seen on Slide 23, these asset jobs have improved our gross operated wet gas production at Cana by roughly 40 million cubic feet a day.
We expect Bcf per well of additional recovery with a payback period of less than three months. We have around 140 additional operated and non-operated wells that can be treated in the core area and we expect to have most of these treated by year-end.
Moving to Slide 24, given the success of these recent efforts at Cana, we opportunistically bolstered our leasehold position in May by acquiring an additional 50,000 net acres in the core of the play.
This transaction closed in late June, increasing our total Cana-Woodford position to approximately 280,000 net surface acres with stacked pay potential including about 30,000 net acres of exposure to the stack, oil and condensate window.
The new acreage further supplements the thousands of undrilled locations we have in this high quality liquids-rich play. Due to the highly competitive economics at Cana, we plan to accelerate activity in 2015.
If you were to include the non-operated activity of our partner in the play, our total rig count at Cana could be around 10 rigs by the first quarter of 2015. This increased activity puts Cana in a position to deliver strong growth for many years.
Moving to Slide 25, we have approximately 150,000 net surface acres in the Powder River Basin prospective for multiple formations including the Parkman, Turner and Frontier. To-date, we have identified approximately 1,000 risk locations across our Powder River Basin position with roughly 75% of these locations associated with the Parkman formation.
Our recent drilling activity was highlighted by two wells targeting the Parkman formation in Campbell County, Wyoming. Initial 30 day production at each of these wells averaged 950 Boe per day of which 95% was light oil. At an average well cost of only $5 million per well, our Parkman program is generating attractive rates of return.
We expect to add a fourth rig later this year and more aggressively develop the Parkman focus area in the second half of 2014 and 2015. With that I'll turn the call over to Tom for the financial review and outlook. Tom..
Thank you, Dave and good morning to everyone. To reiterate John and Dave’s comments, the second quarter was one of strong execution. We delivered operationally by successfully exploiting the high margin production opportunities within our portfolio. And we also delivered solid financial results as well.
Our strong growth in oil production, combined with improved oil price realizations drove our E&P upstream revenue to 2.7 billion in the second quarter. These factors increased oil sales to more than 60% of our total E&P revenue in the quarter, pushing overall upstream revenue 20% higher than the year ago quarter.
Not only are our upstream revenues growing rapidly but our midstream profitability is expanding as well. In the second quarter, our midstream business delivered excellent results, generating 224 million of operating profit.
This result exceeded the top end of our guidance range and represented a 90% increase compared to the second quarter of last year. The year-over-year increase in operating profit was driven by the consolidation of EnLink Midstream and improved marketing margins.
Based on our outstanding results in the first half of the year, we are increasing our full year forecast for midstream operating profit to a range of 775 million to 825 million, an increase of roughly 80 million from the midpoint of our previous guidance.
Moving to expenses, in the second quarter total pre-tax cash costs were well within our guidance range for the quarter coming in at 1.1 billion. Excluding the cost associated with the consolidation of EnLink, pre-tax cash costs for our upstream business were 7% higher than the second quarter of 2013.
Now this amount, a third of the cost increase was attributable to higher operating cost associated with Devon’s rapidly growing high margin oil. The remaining increase was driven by higher production taxes related to our strong revenue growth.
Looking to the second half of the year we expect modest upward pressure on our pre-tax cash cost and this is reflected in our 8-K guidance that will be filed later on today. Overall, the benefits of our high margin oil production, improved price realizations in low class structure significantly expanded our pre-tax cash margins.
In fact our pre-tax cash margins improved by 40% year-over-year to our highest level in recent history. Moving to the bottom line, our strong second quarter performance delivered adjusted earnings of $574 million or $1.40 per diluted share, the 16% increase compared to the same quarter last year.
This improved profitability also translated into higher cash flows as well and we generated cash flow from operations of $2 billion, a 47% increase compared to the year ago quarter. Combined with 2.8 billion of pre-tax proceeds received from the sale of the company’s Canadian conventional gas business in April.
Devon’s total cash inflows for the quarter reached 4.8 billion. In late June, we repay created the $2.8 billion sale proceeds from Canada, we utilize these bonds the free cash flow generated down the quarter and cash on hand to reduce debt by 3.2 billion during the quarter.
At June 30, our net debt declined to $10.8 billion of which $1.7 billion was attributable to the consolidation of EnLink Midstream and it’s non-recourse to Devon. If you were to pro forma of the balance sheet for the closing of our U.S.
divestitures which should occur in the next few weeks, our net debt excluding EnLink’s debt decreased to around $7.5 billion.
So to put this in better perspective this is only around one time's 2014 expected EBITDA and this positions are go forward Devon with a strong investment grade credit ratings across the board and one of the better balance sheets in the E&P space.
Moving to our outlook for the third quarter, we expect our go forward asset portfolio continue to demonstrate excellent year-over-year growth in oil production.
With average daily oil rates ranging 200,000 to 210,000 barrels per day, this guidance implies an expected 30 plus percent increase in oil production from our go forward properties compared to the year ago quarter.
We expect to achieve this excellent growth in spite of the planned turnaround objectives which will limit production by 5,000 to 10,000 barrels per day in the third quarter.
Overall, we expect our go forward asset portfolio to deliver total production in the range of 603,000 to 627,000 Boe per day and this represents a top line growth from our retained assets of more than 10% compared to third quarter of 2013.
Based on our solid execution during the first six months of this year, we remain very comfortable with our previous full year guidance ranges for production. For the full year, we are on track to average more than 600,000 Boe per day from our go forward business driven by full year oil growth rate in excess of 30%.
And finally, as a reminder we will be filing an 8-K later today containing detailed estimates for the upcoming third quarter and for the full year 2014. And will that, I will turn the call back to Vince, for Q&A.
Vince?.
Thank you, operator we are ready for the first question..
Thank you, your first question comes from David Hickman with Hickman Energy Advisor. Your line is open..
I wanted to look at 5-15 days and just talk about each of the objectives you highlighted to get to the risk factor, can you just give us like what was the number one or the number two objective in the Delaware, Leonard, Bone Spring and other just to get to the 30% to 50% risk factors?.
Dave Hager:.
It was the primary things you have to look at, we looked at everything but you look at the prospectivity of the area based on all the well results you have and then you also apply what we call a drillability factor, can they physically be at locations, physically be accessed with our acreage inventory, those are two primary things we look at and then we also are looking at obviously historical production data to help it out and we all put it into what we call in multi-variant analysis but we remove bias and this is a statistical analysis where we are looking at basically trends in an un-bias manner that correlate with prospectivity.
That doesn’t totally substitute for good technical work but it’s an additive to that but those are the main things you are looking at traditional things you are used to David is just good geosciences work, combined with reservoir work and production history..
And I guess where I’m going is, as you get more production history in the Leonard and in the Bone Spring sands, do you expect those risk factors to move up with well performance there, how do things trend over time?.
Dave Hager:.
Well, the latest table constructor we hope the risk factors move down actually because the lower is the better, the way we constructed the table. Yes absolutely, as get more data we expect these risk factors to go down.
And I think the biggest thing we expect to move up perhaps is this column this risked wells per section, because that’s where we simply don’t have enough data to do this kind of multi-variant analysis, because there hasn’t been a lot of wells that have been drilled, six wells per section or eight wells per section in order to get a good history on.
So in this case we didn’t really do that detailed statistical analysis, we just made -- what we think is a very conservative assumption and as we conduct these pilots which we’re doing right now. We think there is great opportunity that we may increase from the four to five wells per section to more wells per section.
But we just want to get some pilot information before we do that..
And then just thinking about that and leading to the 5,000 the likely grows.
What’s the optimal kind of inventory life as you think about the basin relative to the number of wells you drill per year?.
Dave Hager:.
The way we think about it, is we generate as many as we can obviously, then we try to put as many rigs to work as we feel that we can and maintain the quality of our drilling results. So we identify huge new resource inventory, that’s great news.
But then we got to think about what can we actually execute and deliver the results with the risk that we perceive in the basins. So I don’t know if there is an optimum. I mean I would love to have 100 years inventory, totally theoretical standpoint.
But what we’re trying to do is increase the pace of our drill commence with our ability to de-risk the area. And we’re confident we’re going to be able to get somewhat around 20 rigs next year and we’re thinking higher than that internally but we got to walk before we run and so we’ll see where it goes..
Your next question comes from Doug Leggate with Bank of America. Your line is open..
If I could take two questions please. First of all Dave on the Eagle Ford, just to be clear I am assuming you had no inventory in the upper Eagle Ford in your initial analysis when you acquired your southern.
And if that is the case, can you give us some ideas based on (obviously) [ph] a number of third party wells that hoped and drilled near for Eagle Ford.
From what you know today, what would you say about how -- at what proportion your acreage is perspective? And anything you could say about how that may change the inventory count? And I have a follow up please..
Dave Hager:.
Well we had none of this and the inventory at the time we did the acquisition we gave zero value to the upper Eagle Ford. So this is all additive from a value standpoint. As you can see from the isopach map that we included in the presentation, we think the bulk of our acreage is perspective for the upper Eagle Ford.
The key is that there is an ash zone that develops that we think that will contain the fracs that have been done in the lower Eagle Ford from penetrating up to the upper Eagle Ford.
And when we talk upper Eagle Ford, there are a couple of different upper Eagle Ford intervals, just you guys know there is an upper Eagle Ford shale and there is upper Eagle Ford Marl, we’re really talking about the upper Eagle Ford marl which some might call the lower Austin Chalk, but it’s a Marl zone and it is very mapable.
We think the bulk of the acreage is developable for that. How much that adds at this point? Or we think is potentially is developable, we need to get more well results, so before we can quantify too much. And frankly where we’re drilling right now in Lavaca County may or may not be the best part of it. The best maybe in DeWitt County..
My follow up is I guess is a Cana question but it is also kind of an activity question. 5,000 locations the 10 rigs, obviously I am missing something here. What proportion of those 5,000 locations falls into the category of the enhanced frac that you described obviously yourself.
And how does this basically change capital allocation as you move forward in terms of [indiscernible] EBITDA level? I'll leave it there. Thanks. .
John Richels:.
We may go higher than that, that’s a fair enough point Doug. Now this is a recent development with these improved completion designs that are really enhancing the Cana economics. So we are allocating rigs back out there.
we obviously want to see, we’ve been drilling in what we think is some of the best part of the play not all of it is going to necessary quite as good as this but we think it’s still going to be very good. So we’re going to see where these results are, where they take us.
It’s possible that we may continue to ramp the rigs up well beyond the 10 that I mentioned in my previous comments..
Thinking more about the overall portfolio Dave in terms of given the spend for the balance sheet. I mean is there -- how do you see acceleration generally across the portfolio, given where your inventory is building on it pretty much every play now..
Dave Hager:.
John may want to answer this too. But we obviously every year put together a long range plan where we try to balance our ability to execute on the portfolio and maintaining the strong balance sheet. And so this is part of the capital allocation process that we’re going through right now as we speak about where we want to end up on that.
I think the good news is we’re in great financial shape after these transactions.
John you want to add to that?.
And then Doug one thing as Dave said, we are in great shape and we will have to see. We haven’t port our budget for next year, we are still going to be working on that.
I think the really important thing is with the transformation that we have undertaken over the last while, we have put ourselves in the position to be able to live within cash flow and still grow at very, very competitive rates whether we choose to do that or not that’s another question.
We may well, based on our outlook, based on industry conditions and basin conditions, choose to accelerate that in the future as well.
And what’s important is we got the financial capability, in some of the areas or in all of our areas, we want to make sure that we don’t get ahead of the science, we don’t get ahead of the geology, we don’t get ahead of infrastructure, organizational capacity, availability of rigs and service and all of those kinds of things.
So, other items that factor into the pace that we can accelerate at but I will say we are all really excited. We are in a position that we haven’t been in for a while of being able to significantly grow really high margin products and generate high levels of cash flow. So, we feel pretty good about where we are right now..
Your next question comes from Brian Singer with Goldman Sachs. Your line is open..
Wanted to follow-up on the CapEx points you were just discussing. Can you just talk to how you are thinking about CapEx for the remainder of the year and then since you did provide some preliminary oil growth expectations for 2015 within the context of your cash flow and your 2014 budget.
How should we preliminarily think about 2015 levels of spending needed to achieve 20% plus oil growth?.
John Richels:.
Well just for this -- this year, we haven’t changed our guidance for the year, Brian, I think we are on the street at 5 to 5.4 for our E&P capital spending and that’s assuming costs remain the same but we will see how that all sorts out.
And we are halfway through the year and we so far spend about 47% of our total CapEx budget for the year, so we are on track for this year. When we talk about 20% growth in 2015, growth in our oil production 2015, we've done that based on our expectation for cash flow for next year.
So, again as I said earlier whether we -- as we finish developing our budget and take all these other factors that I mentioned when I was replying to Doug, into account, where we actually ended up with a capital budget in 2015 remains to be seen but that 20% number is assuming living within cash flow..
And then shifting back to the Delaware, the acreage position that you have there in New Mexico and Texas probably puts you in a very good position to comment on the quality of the oil and the impact of condensate.
As you continue to drill in various zones and various parts of the play, are you seeing any increased condensate coming out of your wells? Is that impacting your realizations and what are you expecting there going forward?.
Darryl Smette:.
This is Darryl. In Permian Basin, what we have seen pretty consistently is a quality of group between 38 and 42 degrees. The vast majority of that is less than five-tenths of a percent sulfur so it’s classified as sweet crude. There have been individual wells that we have drilled.
We have seen the gravity go up as high as 45 to 46% which has not been consistent through all of our wells. There have been some industry players who have also seen gravity that high, depending on the volume from industry that comes out of that 45 to 46 degree gravity.
It’s pretty well blended in the other crude out there that’s in the 36 to 40 degree, so we really don’t see at least in the foreseeable future that, we are going to have any condensate problems coming out of the Permian Basin. .
Your next question comes from Arun Jayaram with Credit Suisse. Your line is open..
Thank you.
Dave, I wanted to see if you can elaborate on your plans to increase your rig count in Delaware from 12 to 20 and maybe you can maybe just opinion on where your technical understanding is of the play versus a year or two ago and just your confidence in executing a program of that size?.
Yes, well, I think our technical understanding has increased pretty significantly as we have appraised across our entire acreage position that has now put us into a position now that we have a pretty good understanding of what the prospectivity is across our entire acreage position.
There is always risk when you drill well, so it’s not an absolute but I would say our technical understanding because we have been appraising across the entire acreage position, certainly in the Bone Springs is there now.
We still need to drill additional wells and we have a listed inventory in the Wolfcamp and there haven’t been many drill on the New Mexico side and the Wolfcamp, so that’s an area that still takes some additional maturing but there is no question that overall and in some of the other formations such as the Leonard obviously, we haven’t drilled that many wells.
We are drilling our first one right now but the industry has. So we’ve got a pretty hand on what’s going on there.
So, from a technical standpoint most areas are maturing, that is really a little bit less on the technical side is more just getting making sure we have several factors working together to execute and we’re confident we’re going to get there, the aim should be to make sure that we have a high quality rigs and services are available, we have the gas takeaway capacity, and we have the infrastructure in the field from just a pure manpower standpoint to manage this kind of rig capacity.
And so we’re working through all those issues and we’re confident that’s going to allows to do 20 rigs sometime next year..
Okay, and just my follow up.
John, what your longer term thoughts regarding the pipe development and the regulatory approval process on that project?.
We filed the application for 105,000 barrels of project with BP about the end of last year.
So, we’ve been going through the process and it’s moving along very well, we have some consultations that are with some groups that aren’t left but it’s moving along really well and it’s our expectations that we’ll get the regulatory approval for that project probably late this year or early in 2015.
So, it’s moving along really well and of course we still have as you know we haven’t made the final things I mean decision on that yet but something it will have to do this well but it’s moving along and Pike is, that was an area that always appealing to us because it’s directly adjacent to Jackfish and Jackfish is in what looks to be the sweet spot of the oil sands for SAGD development.
So this is a pretty good looking lease. .
Quick follow up, given the Delaware Basin opportunity, Cana-Woodford, Rockies oil, how would Pike now compete for capital relative to your U.S.
onshore growth potential?.
John Richels:.
Yes, that’s a good question. It’s a project that has very, very different characteristics. So, if you just want to compare strictly on a rate of return basis, it doesn’t compete as well because, you are reporting some capital upfront, you get this long stream of cash flow over a longer period of time.
So, they're very different projects, the good part of it is, very, very low geological risk, very low engineering risk, you got this flat production profile for 20 or 25 years and an extremely high cash flow stream that comes with that.
So, it really -- the characteristics of it are quite different and we’ve always thought that having a portfolio that’s has -- that's balanced in some way not only between natural gas, natural gas liquids and oil, we kind of like that balance between light oil and heavy oil too because they trade very differently over time and because they have these different characteristics.
So, those are all things that we have to take into consideration in making that decision, it’s kind of balancing the near term versus the longer term aspects of those two kinds of or two different plays..
Your next question comes from Subash Chandra with Jefferies, your line is open..
Yes, thanks for squeezing me in.
Just a couple of questions I guess first on Pike again, the access pipeline, is that sized for Pike? Or does it have to go through additional expansion for Pike?.
This is Darryl, and yes it is sized for Pike, actually sized for both Jackfish and Pike and it does have the ability with additional pump stations to increase capacity significantly, we currently have about 270,000 barrels a day of capacity on the blended stream and like I said with additional pump capacity we can increase that volume for that pipeline.
So, all of those things have been taken into consideration. I might just add the access pipeline looping the 42 inch line was completed end of the second quarter early third quarter and we are now in the process of line filling that line so which should be operational towards the end of this year. .
John Richels:.
So, those volumes that Darryl is saying that’s really much more than we -- I mean that expansion capability with an extra pumping is actually much more than we need for Jackfish and Pike..
Okay, so it’s in excess of those as well, okay.
And then in Cana, the 10 rigs, is that -- are we still 6 to 8 operated and the balance non-op?.
The 6 to 8, if we do the 6 to 8 operated we really set around 10 by the first of the year if we do the full 6 to 8 which we as I was explained to Doug Leggate, we may do that and we may do more, that would actually be -- get us above the 10 rigs if we do that given what [indiscernible] is doing. And there is -- financially will do that.
We’re just staying by the first year-over-year around 10..
Okay, but combined op, non-op?.
Yes, that’s right..
And any commentary just if you can refresh me on the status of the drilling carriers and where you sort of see the intercompany rig movements take place over the next six months?.
Well, I will start off with the rig movements. There is not a lot of rig movement going on. We are as we described increasing our activity a little bit already in Cana and so we are dropping down activity a little bit in the mix for that.
We will be adding a little bit in the powder as I described but overall not a large movement in rigs in the last half of this year. We will be ramping up as we go into 2015. Now on the carriers, on the Sinopec side, as of June 30th, there was about just over $500 million remaining of the $1.6 billion carry.
On Sumitomo side, there is 345 million remaining of a 1.25 billion total drilling carry. Around the end of the year, we think we would be down to the point on the Sinopec side, where we will be about a little over 150 million left and just under 150 million left on the Sumitomo side that we will utilize in 2015..
John Richels:.
Well folks, I am showing the top of our here but before signing off let me leave you with a few key takeaways from today’s call. First, we have dramatically improved our portfolio in a short period of time. Devon emerges with a formidable portfolio that’s on track to deliver attractive high margin production growth for many years to come.
As evidenced by our second quarter results, our pursuit of high margin production is significantly expanding our margins and profitability. And finally the commitment to our top strategic objective that you heard us talk about often, which is to optimize long-term growth and debt adjusted cash flow per share has never been stronger.
As we deliver on our growth expectations we are poised to create significant value for our shareholders in the upcoming years. So, we look forward to talking with you again on our next call and thank you for joining us today..
Thank you. This concludes today’s conference call. You may now disconnect..