德文能源 (DVN) 2014 Q2 法說會逐字稿

Welcome to Devon Energy's second quarter 2014 earnings conference call.

(Operator Instructions)

This call is being recorded. At this time, I would 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's aware that we have prepared a handful of slides to supplement today's script. These are integrated with today's webcast, and they are also available for download in PDF form on Devon's homepage, www.DevonEnergy.com.

For those that are not participating via webcast, we will make sure to refer to the slide numbers during our prepared remarks so that you can follow along. Today's call will follow our usual format. I'll -- I have a few preliminary items to cover. Then I'll turn the call over to our President and CEO, John Richels, for his comments.

Following John, Dave Hager, our Chief Operating Officer, will provide the operations update, and we will 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 website.

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.

And, in addition to the updates that we are providing on the call, we will file a Form 8-K later today, and it will have the details of our updated 2014 estimates. A copy of this updated 8-K will be available within the Investor Relations section of the Devon website, as well.

The guidance we provide today includes plans, forecasts, expectations and estimates which are forward-looking statements under US securities law. These are, of course, subject to a number of assumptions, risks 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 in our Form 10-K.

Also in today's call we will 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'm 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. On behalf of the Company and the many people you've 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've 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 and Investor Relations. Howard has a long history in the business with over 30 years of experience, the last 12 in much the same role at Marathon Oil and previously at Phillips Petroleum. We are very fortunate to have an individual with Howard's experience join our team, and we welcome Howard to Devon.

I'm 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 US 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 a 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 US assets, which increased an impressive 79% compared to the second quarter of 2013. This dramatic increase in US oil production is 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 onshore 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 developments increased our Company-wide 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 pretax 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 US 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 was also at about a seven times EBITDA, pretax 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 forward 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 US, 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 Company-wide 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 US light oil production. This should drive about 10% top line production growth on a 6 to 1 energy equivalency basis, and on a value or a price equivalency basis, applying a more realistic oil to natural gas price ratio of 20 to 1, expected top line production growth in 2014 would 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 are 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 these high-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 historic 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 over time. In fact, with the technical work that we've 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 drop down additional midstream assets to EnLink. As seen on slide 10 and 11, two potential drop-down 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 top line production growth in the mid-single digits. The Eagle Ford and the Delaware Basin will once again lead our oil production growth in the US, and we will also see significant oil growth from our Jackfish 3 project in Canada, where we recently started steam injection.

In summary, we are 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 are very well-positioned for competitive growth for years to come.

And as we execute on our growth plan, 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, optimize completions design and very efficient production operations.

Continuous improvement of each of the areas and others will provide incremental value in each of our operating areas. 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 us 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 the 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 in Lee 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 the ongoing reservoir characterization work allowed us to substantially increase our risked undrilled inventory.

The stacked pay nature of our position in the 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 in the Delaware Basin provides us with exposure to more than 5,000 unrisked -- to more than 5,000 risked, 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 prospective acres in each formation in the Delaware Basin.

Next, the multi variant analysis I just described was performed by our technical teams, which risk 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 are currently implementing a program in the Delaware Basin that utilizes a much larger and more focused frac design that will 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 rates of 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 risked 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 activity in an orderly fashion as we secure 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 the southern Midland Wolfcamp shale. We increased average net production in this play to 12,000 Boe per day, representing a significant year-over-year increase of 9,000 Boe per day.

In the northern Midland Wolfcamp trend we spot our first horizontal well in Martin County, targeting the Wolfcamp B formation in the third quarter. We have approximately 14,000 net acres in the prolific Martin County area, prospective for 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 in slide 16, while we have only 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 could further enhance well economics and boost our drilling inventory. I'll speak to this in more detail shortly, but let's begin with a review of the second-quarter results.

During the quarter, we had 17 rigs running across our Eagle Ford position, with the majority focused 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 rates 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 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 pretax 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 the 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 30, we had 108 drilled wells not yet producing. We expect this inventory to continue to trend downward over the coming months, as a number of pads are scheduled for tie-in and the 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 -- 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, this keeps -- this second half outlook keeps us on pace to deliver on our previously announced guidance of 70,000 to 80,000 Boe per day for our 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 the 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 can increase well recoveries and, at the same time, reduce well costs. The teams have also identified potential opportunities to improve the rates of return through optimized 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 information.

As seen on the blue -- in 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 the announced wells 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 this isopach map, the majority of our DeWitt and Lavaca County acreage is highly prospective 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 spud 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 tests 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, the significant improvement in Western Canadian select 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 facility's nameplate capacity of 35,000 barrels per day.

In the third quarter, we will bring the Jackfish 1 plant down for a scheduled 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 in Western Oklahoma, where our operations continue 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 [crona] 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 bought online that employed our new redesigned completions, as well as rejuvenated performance from existing wells as a result of our ongoing acid treatment program.

Slide 21 shows the meaningful increase in sand per well along with more frac stages and tighter perf clusters. This new frac design was utilized on the 20 Cana Woodford wells we brought online in the liquid rich core of the play during the second quarter.

Initial 30-day rates 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 1.5 million equivalent barrels per well.

As you can see on slide 22, for the 20 wells we 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 US oil plays.

Our asset team at Cana have also done some outstanding work to revitalize production from existing wells with acid treatments. We have now treated nearly 200 operated and non-operated Cana wells, and the results have been exceptional. In most cases, this inexpensive procedure, around $250,000 per job, took production per well from about 1 million cubic feet equivalent per day up to 2 million a day or more.

As seen on slide 23, these acid jobs have improved our gross operated wet gas production at Cana by roughly 40 million cubic feet a day. We expect about a 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 the 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 risked 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. This is 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's 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 pretax 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, pretax cash costs for our upstream business were 7% higher than the second quarter of 2013.

Of this amount, a third of the cost increase was attributable to higher operating costs 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 pretax cash costs, 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, the improved price realizations and low-cost structure significantly expanded our pretax cash margins. In fact, our pretax 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, that's a 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 pretax 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 repatriated the $2.8 billion sales proceeds from Canada. We utilized these funds, the free cash flow generated in 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 is nonrecourse to Devon. If you were to pro forma the balance sheet for the closing of our US divestitures, which should occur over 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 times 2014 expected EBITDA and this positions our 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 to continue to demonstrate excellent year-over-year growth in oil production. With average daily oil rates ranging from 200,000 to 210,000 barrels per day, this guidance implies an expected 30%-plus 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 at Jackfish, 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 the 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 a full-year oil growth rate in excess of 30%. Finally, as a reminder, we will file an 8-K later today, containing detailed estimates for the upcoming third quarter and for the full-year 2014. With that, I'll turn the call back to Vince for Q&A. Vince?

Thank you. Operator, we're ready for the first question.

(Operator Instructions) David Heikkinen, Heikkinen Energy Advisors.

Congratulations, Vince, on a great career. I wanted to look at slide 15, Dave, and just talk about each of the objectives you highlighted to get to the risk factors. Could you just give us 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?

The primary things you have to look at, David, we looked at everything. But you look at the prospectivity of the area based on all the well results that you have, and then you also apply what we call a drillability factor. Can they physically -- can the locations physically be accessed with our acreage inventory? Those are the two primary things we look at.

We also are looking at, obviously, historical production data to help it out. We all put in into what we call a multi variant analysis, to remove bias. This is a statistical analysis, where we are looking at, basically, trends in an unbiased manner that correlate with prospectivity. That doesn't totally substitute for good, technical work, but it's an additive to that.

Those are the main things you are looking at, traditional things you are used to, David, is just good geoscience work combined with reservoir work and production history.

I guess where I'm going is 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? How do things trend over time?

The way this table is constructed, we hope the risk factors move down, actually. Because, the lower is the better, the way we constructed the table. Yes, absolutely. As we get more data, we expect these risk factors to go down.

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's great opportunity that we may increase from the four to five wells per section to more wells per section. We just want to get some pilot information before we do that.

Just thinking about that and leading to this 5,000 that likely grows, what's the optimal inventory life, as you think about the basin relative to the number of wells you drill per year?

Well, the way we think about it, 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've identified a huge new resource inventory. That's great news.

But, then, we've got to think about what we can actually execute and deliver the results with the risk that we perceive in the basin. So, I don't know if there's an optimum. I would love to have 100 years inventory, totally theoretical standpoint, but what we're trying to do is increase the pace of our drilling commensurate with our ability to de-risk the area.

We are confident we are going to be able to get somewhere around 20 rigs next year, and we're thinking higher than that internally, but we've got to walk before we run. So, we'll see where it goes.

Okay. Thanks.

Doug Leggate, Bank of America.

Thanks. Vince, congratulations and also welcome, Howard. We're looking forward to having you back in the saddle again.

If I could take two questions, please. First of all, Dave, on the Eagle Ford. Just to be clear, I'm assuming you had no inventory in the upper Eagle Ford in your initial analysis when you acquired GeoSouthern.

If that was the case, can you give us some idea based on -- there's obviously a number of third-party wells that have been drilled in the upper Eagle Ford. From what you know today, what would you say about at what proportion of your acreage is prospective and if you could say how about that might change the inventory count and another follow-up, please.

Well, we had none of this in 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 prospective for the upper Eagle Ford.

The key is, 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. When we talk upper Eagle Ford, there's a couple of different upper Eagle Ford intervals, just so you guys know. There's an upper Eagle Ford shale, and there's an upper Eagle Ford marl. We are really talking about the upper Eagle Ford marl, which some might call the lower Austin chalk.

But it's a marl zone that's very mapable. We think the bulk of the acreage is developable for that. How much that adds at this point, or what we think is potentially developable. We need to get more well results though before we can quantify it too much.

Frankly, where we're drilling right now in Lavaca County may or may not be the best part of it. The best may be in DeWitt County.

Thanks for that. My follow-up is kind of a Cana question, but it's also kind of an activity question. 5,000 locations with 10 rigs, obviously I'm missing something here. What proportion of those 5,000 locations folds into the category of the enhanced frac that you described, obviously yourselves and Cimarex?

And how does this basically change capital allocation as you move forward in terms of future activity level? And I will leave it there. Thanks.

Well, we may go higher than that, that's a fair enough point, Doug. It 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 that we've been drilling in what we think is some of the best part of the play. Not all of it's going to be necessarily quite as good as this, but we think it's still going to be very good. We are 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 strength of the balance sheet, is there a point -- how do you see acceleration generally across the portfolio? Seemingly your inventory is building on pretty much every play now.

Well, John may want to answer this, too. We obviously, every year, put together a long-range plan where we try to balance our ability to execute on the portfolio and maintaining a strong balance sheet. So, this is part of the capital allocation process that we are going through right now as we speak about where we want to end up on that.

I think the good news is, we are in great financial shape after these transactions. John, you want to add to that?

Doug, one thing, as Dave said, we are in great shape, and we'll have to see. We haven't poured our budget for next year, still going to be working on that. I think the really important thing is, with the transformation that we've 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 is another question.

We may well, based on our outlook and based on industry conditions and basin conditions, choose to accelerate that in the future, as well. What's important is we've got the financial capability to do it. In some of the areas, -- or in all of our areas -- we want to make sure 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 services and all of those kinds of things.

Those are all other items that factor into the pace that we can accelerate at. But, I will tell you, we are all real 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 at right now.

Good story. Thanks, John.

Operator, next -- go ahead --

Brian Singer, Goldman Sachs.

I wanted to follow-up on the CapEx point you were just discussing. Can you just talk to how you are thinking about CapEx for the remainder of the year?

Then, since you did provide some preliminary oil growth expectations for 2015, within the context of cash flow and your 2014 budget, how should we preliminarily think about 2015 levels of spending needed to achieve 20% plus oil growth?

Well, just for the -- this year -- we haven't changed our guidance for the year, Brian. I think we're on the Street at [$5 million] to [$5.4 million] for our E&P capital spending and that's assuming costs remain the same. But, we'll see how that all sorts out.

But, here we are halfway through the year and we've so far spent 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. Again, as I said earlier, whether we -- as we finished developing our budget and take all those other factors that I mentioned when I was replying to Doug into account, where we actually end up with a capital budget in 2015, remains to be seen. But, that 20% number is assuming that we are living within cash flow.

Got it. Thanks. Then shifting back to the Delaware, the acreage position that you have 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 as impacting your realizations, and what are you expecting there, going forward?

Yes, Brian, this is Darryl. In the Permian Basin, what we have seen, pretty consistently, is a quality of crude 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, where we have seen the gravity go up as high as 45% to 46%, which has not been consistent through all of our wells.

There has been some other industry players we 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 degrees. So, we really don't see -- at least in the foreseeable future -- that we're going to have any condensate problems coming out of the Permian Basin.

Great. Thank you very much.

Arun Jayaram, Credit Suisse.

Thank you. Dave, I wanted to see if you could elaborate on your plans to increase your rig count in the Delaware from 12 to 20. Maybe you can maybe just opine 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.

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's always a risk when you drill wells, so it's not an absolute. But I'd say our technical understanding because we have been appraising across the entire acreage position, certainly the Bone Springs is there.

We still need to drill additional wells, and we haven't listed inventory in the Wolfcamp. And there haven't been many drilled on the New Mexico side of the Wolfcamp, so that's an area that's still -- take some additional maturing. But there's 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 industry has. We've got a pretty good handle what's going on there.

From a technical standpoint, most areas are maturing. It's really a little bit less on the technical side. It's more just getting -- making sure we have several factors working together to execute. And we are confident we are going to get there.

The issue would be to make sure that we have the high-quality rigs in services that 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. So, we are working through all those issues, and we are confident that's going to allows us to do 20 rigs next year, sometime next year.

Okay. And just my follow-up -- John, what are your longer-term thoughts regarding the Pike development the regulatory approval process on that project?

Well, we filed the application for the 105,000-barrel a day project with BP about the end of last year. We've been going through the process, and it's moving along very well.

We have some consultations with some groups that are left, but it's moving along really well. And it's our expectation 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.

Of course, we still have -- as you know -- we haven't made the final sanctioning decision on that yet. That's something that we will have to do this fall. It's moving along, and Pike is -- that was an area that was 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.

John, just a quick follow-up. Given the Delaware Basin opportunity, Cana Woodford, Rockies Oil, how would Pike now compete for capital relative to your US onshore growth potential?

That's a good question. It's a project that has very, very different characteristics.

If you just want to compare strictly on a rate of return basis, it doesn't compete as well, because you're putting some capital up front. You get this long stream of cash flow over a longer period of time. So, they are very different projects.

The good part of it is, there's very, very low geological risk, very low engineering risk. You've got this flat production profile for 20 years or 25 years and an extremely high cash flow stream that comes with that. It really -- the characteristics of it are quite different.

And we've always thought that having a portfolio that 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. Those are all things 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.

We've got time for one more question.

Subash Chandra, Jefferies.

Just a couple of questions. 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. Yes, it is sized for Pike.

Actually it's sized for both Jackfish and Pike, and it does have the ability with additional pump stations to increase capacity significantly. We currently have about 207,000 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 first -- third quarter. And we are now in the process of line filling that line, so it should be operational toward the end of this year.

The volumes that Darryl's talking about, that's really much more -- that expansion capability with the extra pumping is actually much more than we need for Jackfish and Pike.

Okay. It's in excess of those, as well. Okay.

Then, in Cana, the 10 rigs, is that -- are we still six to eight operated and the balance non-op?

Yes. The six to eight, if we do the six to eight operated, we really said around 10 by the first of the year. If we do the full six to eight, which as I was explaining to Doug Leggate, we may do that and we may do more. That would actually get us above the 10 rigs, if we do that, given what Cimarex is doing.

There's a good chance we will do that. We are just saying by the first of the year we will be around 10.

Okay. But combined, op, non-op?

Yes. That's right.

Any commentary, just if you can refresh me on the status of the drilling carries and where you see the inter-company rig movements take place over the next six months?

I'll start off with the rig movements. There's not a lot of rig movement going on. We are, as earlier described, increasing our activity a little bit in the -- already in Cana, so we're dropping down the 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, though, as we go into 2015.

Now, on the carries, on the Sinopec side, as of June 30, there is about just over $500 million remaining of the $1.6 billion carry. And on the Sumitomo side there is $345 million remaining of $1.025 billion total drilling carry. Around the end of the year, we think we'd be down to the point on the Sinopec side where there'll be a little over $150 million left and just under $150 million left on the Sumitomo side if we utilize in 2015.

Perfect. Great. Thank you very much.

Folks, I am showing the top of the hour here. 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, you've 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. 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.