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.

Arun Jayaram – Credit Suisse Doug Leggate – Bank of America Merrill Lynch Brian Singer – Goldman Sachs Subash Chandra – Jefferies & Company Jeffrey Campbell – Tuohy Brothers Investment Research.

Welcome to Devon Energy’s First Quarter 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 Communications and Investor Relations. Sir, you may begin..

Thank you and welcome everybody to Devon’s First 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 presentation.

The slides are integrated with today’s webcast but they’re also available for download in PDF form on Devon’s home page at 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 as I will first cover a few preliminary items and then turn the call over to our president and CEO, John Richels, for this comments; then Dave Hager, our chief operating officer will provide an operations update and we’ll wrap up our 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 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.

In addition to the updates that we are providing in the call, we will file an 8-K later today containing the details of our updated 2014 estimates. The copy of this updated 8-K will be available within Investor Relations section of the Devon website.

The guidance that we are providing today includes plans, forecast, expectations and estimates which are all considered forward-looking statements under US Securities Law and these are of course subject to a number of assumptions, risk and uncertainties many of which are beyond our control.

These statements are not guarantees of future performance and for a discussion of the risk factors relating to our estimates see our Form 10-K. Also in today’s call, we’ll reference certain non-GAAP performance measures. When we use these measures there are required specific related disclosures and those can also be found on our website.

At this point, I’ll turn the call over to our president and CEO, John Richels..

Thank you, Vince, and good morning everyone. Before we get in to the business of the quarter, I’d like to take just a moment here to welcome our latest edition to Devon’s team of senior executives and that’s our chief financial officer, Tom Mitchell.

Many of you already know Tom and you know that Tom brings a wealth of industry experience and considerable financial sophistication and we’re thrilled to have him on board.

As Vince already mentioned, you’re going to hear from Tom later on in the call and as you have the opportunity in the coming months to meet with him, please join us in welcoming Tom to Devon. So with that, let’s take a look at our results. The first quarter was another excellent one for Devon.

As shown on slide three, our disciplined focus on high-margin oil development opportunities led to another quarter of outstanding growth in oil production that drove significant operating margin improvements. Additionally, we made meaningful progress in our efforts to high grade our go-forward asset portfolio.

This progress was evidenced by the closing of our Eagle Ford acquisition, the completion of the EnLink Midstream combination, our exit from the conventional gas business in Canada, and our recently announced bolt-on [ph] acreage acquisition in Cana. In addition, we once again raised our dividend during the quarter.

Now, let’s take a look at some of the highlights in more detail. In the first quarter, we achieved year-over-year oil product growth of 21% from go-forward asset base reaching an average daily rate of 176,000 barrels per day.

As can be seen on slide four, this growth was driven entirely by light sweet crude production from our retained US assets which increased an impressive 56% compared to the first quarter of 2013.

With our success in growing high-margin production, we expect oil and natural gas liquids to approach nearly 60% of Devon’s go-forward production mix by year end. In addition to our robust growth in high-margin oil production, we benefited from the sharp rise in natural gas pricing and improved Canadian heavy oil realizations.

This increased first quarter upstream revenue by 42% compared to the first quarter of 2013. As shown on side five, 67% of our upstream revenue came from liquids. Higher revenues coupled with our low cost structure drove operating margins by more than 50% year over year.

Another notable first quarter financial highlight was a 9% increase in Devon’s quarterly cash dividend to $0.24 per share. This is Devon’s 9th dividend increase since 2004 representing an annual compound growth rate of 23%.

Our dividend increase reflects Devon’s long-term commitment to returning cash to our shareholders and ultimately underscores the confidence we have in our business.

Looking beyond our operating and financial results for the quarter, we did an outstanding job in the past few months in executing our portfolio transformation which is now nearly complete. The first major milestone occurred on February 28th with the closing of our Eagle Ford acquisition.

This acquisition of 82,000 net acres in the economic heart of the play adds a new light oil core area to Devon’s portfolio, offering some of the highest rate of return drilling opportunities in North America.

While we’ve only owned this position for a short time, the reservoir performance that we’ve seen to date has been outstanding, fully supporting our production growth targets and double digit accretion in cash flow per debt adjusted share. One week later, on March 7th, we closed on our Midstream combination with Crosstex to form EnLink Midstream.

EnLink units are now trading on the New York Stock Exchange under the ticker symbols ENLC for the general partner and ENLK for the MLP.

And while the assets we contributed were valued in the transaction at about $4.8 billion, the ownership interest in the EnLink securities that we received had a market value at yesterday’s close of more than $7.5 billion or approximately 27% of our current market capitalization.

This valuable ownership was attained by contributing most of Devon’s US Midstream assets to EnLink. The contributed assets accounted for only 7% of Devon’s cash flow last year.

Furthermore, the loss of this direct Midstream cash flow was offset by our receded [ph] quarterly distribution payments from EnLink and EnLink’s assumption of the associated capital obligations. Looking beyond these immediate benefits, we’re also excited about the attractive long-term growth prospect associated with this business.

The stable fixed fee structure, the deep backlog of liquids oriented projects and the future drop down potential from both Devon and from the general partner provide a foundation for EnLink to deliver attractive distribution growth for many years.

We took another significant step forward in our transformation in early April by closing the sale of our Canadian conventional business for CAD3.125 billion.

This was the largest divestiture package in our non-core asset sale process and we attractively monetize these gas-weighted assets at nearly seven times EBITDA which is a substantial premium to Devon’s current trading multiple.

After adjusting for currency exchange and taxes associated with both the sale and the repatriation of the funds to the US, we’re receiving net proceeds of US$2.7 billion.

For our remaining divestiture assets which are all located in the US, we’re putting the final touches on the data rooms with the expectation to complete the sale of all non-core assets by year-end.

Most recently, we opportunistically added to our core Cana-Woodford position by acquiring an additional 50,000 net acres and 5,800 equivalent barrels per day of production. These assets directly overlap our existing core Cana position and expand our opportunity set with exposure to other Western Oklahoma oil and gas plays.

This move is consistent with our philosophy of building scale and scope in our core play areas. Later on the call, Dave will discuss some recent positive developments to Cana that led to our decision to acquire the additional interest.

The bold steps we’ve recently taken to high grade our asset base have positioned Devon with a formidable and balanced portfolio focused on fewer core areas in some of the most attractive basins in North America. Our retained asset base consists of three world class oil development plays in the Permian Basin, the Eagle Ford, and Canadian Oil Sands.

And two of the best liquids rich gas there is in the U.S., the Barnett Shale and the Anadarko Basin. Each of these core areas has the inventory to materially grow production and sufficient scale to generate substantial amounts of cash flow.

Our capital budget for these retained properties in 2014 is around $5 billion concentrated in our three high margin oil development plays. Looking at slide six, company-wide oil production is expected to grow by more than 30% year over year led by a 70% plus increase in U.S. oil production.

This should drive grow of about 10% in top line production on an energy equivalent basis or 20% higher on a 20-1 price equivalency basis. As evidenced by our solid first quarter performance, we are well on our way to achieving these attractive growth targets.

In addition to the growth we’re delivering in 2014, Devon is also positioned for significant high margin oil growth in 2015 and beyond. That’s illustrated on slide seven, where you can see that we expect Devon’s retained asset base to generate organic oil production growth in excess of 20% in 2015.

Let’s take a look at the specific drivers of this oil growth. Our most significant growth next year will come from low risk, infill drilling in the Eagle Ford where we expect production to average well over a 100,000 BOEs per day.

In addition to this exceptional volume growth trajectory, this highly profitable production will also deliver a powerful free cash flow stream that should exceed $1 billion based on the current prices. So, just to be clear, that’s free cash flow is cash flow in excess over capital investment.

Another driver growth in 2015 will be the acceleration of drilling activity in the Delaware Basin specifically in South-East New Mexico. Over the next year, we will accelerate development of our rapidly growing resource potential in that area.

And Dave is going to provide more details on our significantly expanding inventory and significantly growing resource potential in this prolific basin later on in the call. And lastly in Canada, the start up of our Jackfish 3 facility later this year will commence another leg of multi-year oil production growth from our thermal oil business.

In 2015, we expect net oil production from our Jackfish complex to increase to a range of between 62,000 and 67,000 barrels per day, representing a year-over-year growth rate of approximately 30%.

Furthermore, the completion of Jackfish 3 will lower Devon’s overall capital intensity and begin an era of free cash flow from our Jackfish complex with the potential to generate up to $1 billion annually for many years.

As you can see on slide eight, this wall of cash provides a significant source of capital for E&P investment, debt reduction, dividends, and share repurchases. So, in summary, I’ve never been more excited about Devon’s future than today.

As outlined on slide nine, Devon has established itself as one of the largest oil producers among our North American onshore peers. When you combine the growth potential of our top tier oil development projects with our high quality natural gas optionality, we are a well positioned for extremely competitive growth rates for years to come.

What makes our growth story even more compelling is Devon’s attractive valuation. Backing out the value of the EnLink securities from our enterprise value and EBITDA reveals that our E&P business is trading at just over four times EBITDA.

As we continue to execute on our growth plan, Devon shares’ have the potential to benefit not only from improving margins and higher cash flow, but also through multiple expansion.

So, with that, I will turn the call over the Dave Hager for a more detailed operations review, Dave?.

Thanks, John. Good morning everyone. Let’s begin with a quick recap of our first quarter capital expenditures. Exploration development capital for the first quarter totaled $1.2 billion, just below the bottom end of our previous guidance range.

Based on our planned activity levels to the remaining three quarters of 2014, we remain on track with full year drilling and completions capital guidance range of $4.8 billion to $5.2 billion for our go-forwards assets. As John indicated earlier, our focus on high margin oil projects led to another quarter of outstanding growth in oil production.

Let’s take a closer at some of the first quarter operating highlights, beginning with the Permian; first quarter production averaged a record 91,000 barrels of oil equivalent per day. This record was driven by robust growth in oil production, which increased 36% compared to the first quarter of 2013 and with 9% higher than the previous quarter.

Light oil production continues to account for 60% of our total Permian production. In the Delaware Basin our Bone Spring horizontal program is the most significant driver of our Permian oil growth.

In the first quarter, we bought 35 Bone Springs wells online with an average 30 day IP raise approaching 700 barrels of oil equivalent per day of which 80% was light oil. Also in the Delaware Basin, we commenced production on two high rate oil wells targeting the Delaware Sands and Lee [ph] New Mexico.

Initial 30 day production from these two wells averaged in excess of 1,000 BOE per day and consisted of nearly 90% light oil. The tremendous results we continue to see from our Delaware Basin drilling programs coupled with our ongoing reservoir characterization work has allowed us to substantially increase our risk inventory in the Delaware Basin.

To help you more fully appreciate the scale and scope of our potential new Delaware Basin, I want to turn your attention to slide 10, which illustrates our acreage position by prospect [ph] deformation.

As you can see the stack pay [ph] nature of our position and the Delaware Basin provides us with exposure not only as a Bone Spring and Delaware Sands, but also the Leonard Shale, Wolfcamp and several other oil zones. If you add up this lease hold buy [ph] formation you can see we have approximately 500,000 net acres to appraise and develop.

Turning to slide 11, you can see this translates into a significant inventory of undrilled locations for Devon. Our largest and most economic opportunity is in the Bone Spring, we recently completed our comprehensive reservoir evaluation on a large portion of our Bone Spring acreage position.

This work combined with strong well performance and successful appraisal drilling in several step-out areas has allowed us to add some 1,900 additional locations to our Bone Spring inventory.

This booze [ph] an undrilled Bones Spring inventory to 3,500 locations, adding locations in the Delaware Sands, Leonard Shale and several other formation brings our total risk inventory at the Delaware Basin for more than 5,000 undrilled locations.

To put this on prospective at our current activity levels, this represents more than 25 years of drilling inventory in the Delaware Basin. Keep in mind these are rest [ph] locations and do not include any location to our Wolfcamp acreage which we are currently evaluating.

We fully expect additional inventory increases over time as Devon and the industry continue to de-risk this world class oil basin. With this significant inventory in the Delaware Basin as I can provide some thoughts on how we will approach converting this resource into production and cash flow.

Today, we are running 12 rigs in the Delaware Basin, the appropriate level of activity given the availability in South-East New Mexico of gas gathering and processing capacity, high quality rigs, completion services and manpower.

Our program in 2014 is focused almost entirely on our high rate of return and low risk Bone Spring development opportunities. Over the next year, we expect additional capacity build out within this portion of the Permian to support additional activity to further exploit our rapidly growing resource inventory in the region.

While we are not ready to provide specific plans, our preliminary view on 2015 is that we will have the opportunity to significantly increase our drilling activity next year.

This will allow us to continue aggressively developing our highly profitable Bone Spring and accelerate the development and appraisal of our Delaware Sands, Leonard Shale and Wolfcamp well inventories. Given our outlook for significant cash flow growth next year, we clearly have the means to fund a more robust level of activity.

As John highlighted in his opening remarks, the acceleration of drilling activity in the Delaware Basin is a visible source of future light oil production in 2015 and will remain a cornerstone asset for Devon for many years to come.

Shifting to the Southern Midland Basin, we will continue to see solid results from our oil development program, the Wolfcamp Shale, where we have a joint venture partnership with Sumitomo. During the first quarter, we tied in 26 Wolfcamp Shale wells, increasing our average net production in the play to an average of 10,000 BOE per day.

Compared to the first quarter of 2013, this represents production growth of 8,000 BOE per day. Moving to the Eagle Ford, as John mentioned, we completed our acquisition of 82,000 net acres in Eagle Ford on February 28 and resulted in one month of production in our first quarter reported results.

Although we have only owned these assets for a couple of months now, we couldn’t be more pleased with the quality and with our joint venture relationship with BHP in DeWitt County.

The well and reservoir performance that we have seen today reinforces our previous forecast for average net daily production of 70,000 to 80,000 BOE per day for the 10 months we will own this asset this year. We are also on track to deliver well an excess of 100,000 BOE per day in 2015.

As many of you are aware through recent BHP disclosures, March production on our DeWitt County acres was temporarily constrained by third party gathering system downtime and the timing of well tie-ins.

In Eagle Ford, the production growth profile for most operators is somewhat lumpy due to nature or pad drilling and the Devon BHP partnership is no exception. With wells being bought on in groups as many as 20 at a time and the time in bringing on necessary infrastructure to tie into wells, the production growth would tend to come in step changes.

For March, our first month of ownership, our net Eagle Ford production averaged 49,000 barrels of oil equivalent per day. However, as shown on Slide 12, an increase in well tie-ins at the end of March and in April had driven our net daily production up to 64,000 BOE per day currently.

We expect to average between 65,000 and 70,000 BOE per day for the second quarter. And for the second half of the year, we expect our Eagle Ford production to increase to a range of 80,000 BOE to 85,000 BOE per day. Our growth in the Eagle Ford in the second half of this year has been driven by a large number of well tie-ins during that period.

Our Eagle Ford drilling program remains on plan and at quarter end, we had an inventory of about 120 wells drilled but not yet producing. In the second half of the year, we expect this inventory to trim downward as we catch up on pad tie-ins and necessary transportation system permits [ph] are completed in DeWitt County.

As I mentioned earlier, for the 10 months we will own the asset in 2014, we are on track to achieve our previously announced guidance of an average of 70,000 to 80,000 barrels per day.

In addition to world-class oil development in DeWitt County, we are excited about the emerging opportunities we see ahead of us on our 32,000 net acres in Lavaca County.

As you can see on Slide 13, recently announced well results in – by industry in this area represented in blue have included initial oil production rates of more than 1,000 barrels of oil per day. These results have far exceeded our expectations for the area.

And with less than 10% of the acquisition value assigned to our 32,000 net acres, we are extremely encouraged with the upside potential on this acreage. We expect to bring our first Lavaca County wells online in the second quarter, and as previously disclosed, expect to participate in roughly 30 gross wells for the full year.

And lastly, I want to briefly mention another potential upside we have identified across our entire position in the Eagle Ford. We have mapped our acreage position in Lavaca and DeWitt County and believe that most of our acreage is respectfully [ph] for the upper Eagle Ford formation.

Our belief is supported by recently industry results as noted in green on slide 13. We are evaluating these results and the timing of our first operated well to test the upper Eagle Ford.

Moving now to our thermal oil projects in Northeast Alberta on slide 14; first quarter gross production from our two Jackfish projects averaged roughly 62,000 barrels of oil per day or roughly 52,000 barrels per day after royalties.

At Jackfish 1, gross production averaged 37 barrels per – 37,000 barrels per day or 29,000 barrels per day net of royalties. The success of our ongoing efforts to improve steam efficiency and well productivity allowed us to exceed the facility’s nameplate capacity of 35,000 barrels a day during the quarter.

Recently, we have seen excellent results from efficiency modifications to our steam generators, lowering steam chamber pressures, optimizing the temperature profile in the steam chamber and conducting well stimulations.

Continued success from these and other efforts underway to lower our steam oil ratio could result in continued growth and production above nameplate capacity. Construction of Jackfish 3 is essentially complete and plant commission activities are well underway. We expect to begin injecting steam in the third quarter of this year.

Delivery of first oil is scheduled to occur late this year with production ramping up throughout 2015. At Pike, our thermal oil sands joint venture with BP, the approval process for the first stage of the Pike development remains on track. And we expect to receive regulatory approval later this year.

As a reminder, the Pike 1 development project will have ultimate gross production capacity of 105,000 barrels of oil per day. Devon operates Pike with a 50% working interest. Shifting now to the Anadarko Basin in Western Oklahoma, our liquid rich Cana-Woodford Shale play average a record 60,000 BOE per day in the first quarter.

As John mentioned, our recently announced transaction in the Cana-Woodford allows to increase our scale and scope in one of our core liquid rich gas plays and in a cost of less than $2 per BOE for the roughly 150 million barrels of rich [ph] resource. The additional 50,000 net acres increases our core Cana position to approximately 300,000 net acres.

We were particularly excited to acquire this acreage after seeing some positive results from our recent technical work in the area. With the asset teams focused on managing base production, we discovered through reservoir engineering including pressure transient analysis, that we had enhancement opportunities on many of our core area producing wells.

We have now performed these enhancements on about 70 producing wells and the results have been outstanding. In most cases, this inexpensive treatment took production per well from around 1 million cubic feet equivalent per day up to 3 million a day or more.

We believe these efforts should increase EURs by about a Bcf per well with a payback period of less than three months. We have indentified more than 200 additional wells that can be treated in the core area including wells on our new acreage. In addition to this technical work, we continue to make improvements to our completion design.

With our most recent wells, we have doubled the number of frac stages and increased the amount of propane [ph] pumped to about 6 million pounds per well, a 70% increase over our previous jobs. The results from these completion improvements, as well as our downhole work on the existing producers, had been outstanding.

Production performers from these wells are exceeding our type curve model and significantly enhancing our rate of return. These stronger returns have improved the competitiveness of our Cana drilling within our portfolio, which ultimately led us to take advantage of the opportunity to acquire additional acreage.

We’re evaluating the impact of the acquisition and the recent technical advancements at Cana on our capital allocation plan and we’ll discuss any modification during next quarter’s call.

Looking at our Mississippian-Woodford trend in North Central Oklahoma, we brought 63 operated wells online during the quarter within the Sinopec joint venture area with overall results supporting our type curve expectations.

Solid performance from these wells help drive our average first quarter production in the trend to 19,000 BOE per day of which 50% was light oil. This represents a production growth rate of 35% compared to the fourth quarter of 2013.

The focus of our activity this year is on the JV area where we have the benefit of a carry and are seeing the most consistent results. And finally, our Rockies assets continue to deliver excellent results with net production averaging 20,000 BOE per day in the first quarter.

Liquids production in the Rockies increased 21% compared to the first quarter of last year and account for nearly half of Devon’s product mix in the region.

Our activity was highlighted by two high-rate oil wells brought online during the quarter, an Iberlin Ranch well targeting the Frontier formation that’s tied in with initial 30-day production rates averaging 2,000 BOE per day including more than 1,700 barrels of oil per day.

We also commenced production on a well targeting the Parkman formation with 30-day production rate and averaging an excess of 1,100 BOE per day of which 96% was light oil. Devon has 150,000 net acres in the Powder River Basin prospective for multiple formations including the Parkman, Turner and Frontier.

The company has identified approximately 1,000 risked locations across the Powder River Basin and expects its drilling inventory to increase as the company de-risks this oil opportunity. So in summary, we had another strong quarter of execution across our entire North American onshore portfolio.

The core focus areas that I discussed today on the call are delivering highly economic and robust production growth for Devon. And with our drilling inventory of opportunities, we’re poised to deliver impressive oil growth in 2014 and beyond. With that, I’ll turn the call over to Tom for the financial review and outlook. Tom..

Thank you, Dave, and good morning everyone. Today, I’ll take you through a brief review of our financial and operating results in the first quarter and where called for provide a state of guidance. Before I get started, I wanted to remind everyone of the changes in our first quarter financial reporting resulting from the EnLink transaction.

Now that Devon is the majority owner in EnLink, accounting rules require that 100% of EnLink’s revenues, expenses, debt and capital are consolidated within our financial statements. The minority ownership interest from the portion that we do not own will be netted and deducted on a line item in the financials entitled non-controlling interests.

Due to these accounting changes, the comparability of first quarter results to prior quarters from a trend analysis perspective is challenging. However, in our earnings release and in our upcoming SEC filings, we’re providing supplemental schedules that will break out the results of our upstream business on that of EnLink.

Since John covered the first quarter production highlights earlier in the call, I will begin with a quick review of our outlook of production. In the second quarter, we expect our go-forward asset portfolio to deliver total production of 609,000 to 631,000 BOE per day.

This represents top line growth from our retained assets of approximately 15% compared to the second quarter of 2013. Most importantly, this expected increase on production is underpinned by a strong, high-margin oil growth.

For our go-forward properties, we are forecasting oil production in the second quarter to increase by roughly 30% year-over-year to a range of between 200,000 and 210,000 barrels per day.

This excellent growth in the high-margin oil production is driven by a full quarter of Eagle Ford production and continued success in our Permian development programs.

For the full year, we remain comfortable with our previous guidance range and on track to produce between 579,000 and 622,000 BOE per day from our go-forward business, driven by a full year growth rate in excess of 30%.

Moving to our upstream revenue, in the first quarter, improved priced realizations for all products combined with higher oil production drove our E&P upstream revenue to $2.6 billion. This represents an increase in oil, gas, and NGL sales of 42% compared to the year-ago quarter.

The most notable improvements in regional pricing were attributable to our Canadian heavy oil production, strong gas realizations from our retained U.S. portfolio and a meaningful price uptick in mid-continent NGLs. In the first quarter, oil sales alone excluding NGLs accounted for more than 50% of our E&T revenue.

Turning now to our midstream business, once again, our midstream business delivered excellent results generating $183 million of operating profits in the first quarter, a 47% increase compared to the first quarter of last year and about 27% above the high end of our guidance range.

Improved price realization and effective cost management were the key drivers behind our first quarter outperformance. Our first quarter results did include 25 days of contribution from EnLink which amounted to $50 million of operating profits.

Based on our strong start to the year, we’re confident of our full year forecast for midstream operating profit of $685 to $755 million. Moving to expenses overall, our first quarter pre-tax expenses were generally in line with our expectations totaling $1.8 billion.

Excluding the cost associated with the consolidation of EnLink, pre-tax expenses were 8% higher than the first quarter of 2013. The increase in unit cost is attributable to higher production task and operating expenses associated with the company’s rapidly growing high-margin oil production.

In addition, $22 million of non-recurring G&A transaction expenses associated with EnLink, Energy or Southern transactions and a change in our timing of our annual stock-based compensation grant resulted in an increase in the first quarter G&A. This stock-based equity grants were previously made in the fourth quarter of each year.

However, to better raise stock-based compensation to the year’s performance, the 2013 grant was delayed to the first quarter of ‘14 resulting in no grant during the calendar year of 2013.

In the upcoming quarter, we expect improvements in our unit cash cost looking specifically at our largest cash cost, least operating expense, we expect second quarter LOE to decline by about 5% sequentially to a range of $9 to $9.25 per BOE.

This expected improvement in unit LOE cost is driven by our first full quarter of production from our low cost Eagle Ford assets and our high cost Canadian conventional business that took effect at the beginning of April. For those of you modeling Devon, it’s important to incorporate the change in our go-forward DD&A rates.

In the second quarter, we expect DD&A expense to increase to a range of $13 to $14 per BOE. This increase in DD&A which of course is a non-cash expense is primarily attributable to a full quarter of depletion expense associated with our newly acquired Eagle Ford properties and the consolidation of EnLink.

For the full year, our DD&A forecast remains unchanged at $12.5 to $14.5 per BOE. Cutting to the bottom line, our non-GAAP earnings increased to $547 million or $1.34 per share. This is more than double our earnings per share in the year-ago quarter and comfortably exceeded the Wall Street consensus expectations.

This improved profitability translated into higher cash flows with first quarter operating cash flow totaling $1.4 billion, a 41% year-over-year. Before we open the call to Q&A, I’ll conclude my remarks with a quick review of our balance sheet and liquidity.

At the end of the first quarter, our financial position remains strong reflecting an investment grade credit ratings across the board. With cash balances at $2 billion, we exited the quarter with a net debt balance of $13.5 billion. Of this amount, $1.5 billion of net debt is attributable to EnLink and is non-recourse to Devon.

If you include the proceeds from the closing of our Canadian conventional divestiture package in early April, our net debt decreased to about $11 billion or just over $9 billion if you exclude EnLink’s net debt. Looking ahead, any proceeds from our U.S.

divestiture process will be utilized to reduce debt further strengthening our high quality balance sheet. So with that, I’ll turn the call back over to Vince for Q&A. Vince..

Operator, we are ready for the first question..

Your first question comes from the line of Arun Jayaram of Credit Suisse. Your line is open..

Good morning, gentlemen. It seems like the strong of the quarter was the Delaware Basin inventory update. So I just wanted to know if you can maybe elaborate a little bit on what drove the increase in the inventory. I believe your type curve was around 500 Mbo.

Any thoughts on overall well performance? And I know you’re not ready to talk about the program next year.

But could we see a pretty significant increase in activity? And how many rigs you’re running today in the Delaware?.

Hi Arun, this is Dave. I’ll take a stab at that. We’re currently running 12 rigs in the Delaware.

And yes, as we said, we do anticipate a significant increase next year as we work our way through all the limitations that currently exists out there – the availability of cash processing capacity, availability of rigs, completion crews, manpower, et cetera. And we’re working through all of those factors as we speak. Yes, this was a big story for us.

And there are really two key things that factored into this, one is we have continued to appraise our acreage position throughout the Delaware Basin particularly in Lea and Eddy County. And so as we’re getting those results, it’s given us greater confidence to up our risk inventory.

And obviously the results from those wells have been outstanding throughout our acreage position. And second, frankly, we’ve just taken the time to look at it in a more comprehensive manner than we’ve been able to do previously. And then we looked at it more comprehensively coupled with the outstanding well results across our entire acreage position.

We suspected it was there, but we were basically able to move into our risk inventory. And so we feel very good. And I would point that the slide that we included there, Slide 11, did not include anything for the Wolfcamp. And the Wolfcamp we think has tremendous prospectivity in Southeastern Mexico.

There’s just not a lot of wells have been drilled there yet. So we think as there’s additional wells drilled in that area that that inventory is going to increase also..

Okay. My question is on the Eagle Ford. It sounded like you’re well on track in terms of ‘14 despite the lower March. But as we think about the ‘15 program, a lot of confidence here around production north of or in excess of 100,000 barrels a day.

Can you just talk about the confidence in the ramp and what’s given you that confidence? Is there early well results or what?.

Yes, I’ll take a stab at that again, Arun. Absolutely, the well results have been 100% consistent with our acquisition expectations. These are outstanding wells. These are wells in the core of the core of the Eagle Ford. And so that gives us tremendous confidence, our infrastructure needs, our continuing to be build out.

Frankly we think that already in the first couple of months that we’ve owned the asset, that grains [ph] have improved efficiency to the overall process and all of that put together gives us tremendous that we’re going to have the ramp that we talked about..

And Arun, it’s John. One thing I’d just toss in here to what David has already said, you’ll recall that when we did that acquisition, we indicated that GeoSouthern and BHP prior to the acquisition had drilled at least one well on every drilling unit across the DeWitt County acreage.

So this confidence that Dave is talking about at Wall Street by the fact that we’ve got pretty darn good idea about what every drilling unit on that acreage looks like..

Okay, that’s great. Then just final question, as we think about heavy oil for the balance of the year, just thoughts on how you see that market playing out. And I know in ‘15, one of the potential headwinds exists on the Alberta Clipper, which hasn’t been approved yet by the State’s requirement.

Any thoughts on ‘15 heavy oil differentials and is there enough rail maybe to soften the blow of the Alberta Clipper?.

Yes, this is Darryl. You’re exactly on point. We do expect that we’re going to see increased takeaway capacity with the Flanagan South pipeline. That’s due to come on mid-2014 probably later part of July is the date that we’re getting out to Enbridge. That’s a 585,000 barrel a day pipeline.

We have a couple of permits that we have to get from the BOM, but anticipate that that will come on stream. That will bring additional capacity from Chicago down to the Cushing hub and then onto the gulf coast. The Alberta Clipper is the line that runs from Hardisty in Alberta down to the neck points in the mid-continent.

That would add about 800,000 barrels a day of capacity. That is generally requiring only additional pump stations or more horse power, not additional line looping. We’re awaiting on or they’re awaiting – Enbridge is waiting on the government to issue those permits.

The latest indication, we have from them is that they will expect those permits later on this year and so that capacity should be operational sometime in 2015..

Thanks a lot..

Darryl, could you just bring that all together and summarize – I mean you have a lot of detailed knowledge there clearly, but summarize what this means for differentials..

Well, in terms of differentials, they’ve been fairly volatile. And supply and demand have been fairly balanced over the last couple of years. And we have seen that volatility ranging anywhere from $20 up to as high as $40.5.

With that additional capacity coming on stream including some additional capacity, some of the refineries, we think those differentials will have downward pressure.

So while they’ll still remain volatile, we think that they’ll be on that $20 to $25 barrel range and maybe $26 barrel range consistently rather than the volatility that we’ve seen from $20 up to $40 or $45..

Thank you..

And no, Vince, I might also add just as an addition there, is that we do have as an industry as lot of rail capacity now. Two years ago, as an industry, we had about 125,000 barrels or rail capacity out of Canada to United States. By the end of this year, that will be close to 650,000 barrels a day.

So not only are we hopeful with the pipelines coming on stream, but there is also the additional rail capacity that makes us feel very good about where differentials are going..

Great. Operator, I want to remind everybody to limit their questions to one initial inquiring and one follow up. And we’re ready for the next participant..

Your next question comes from Doug Leggate from Bank of America Merrill Lynch. Your line is now open..

Thanks. I appreciate you getting me engaged. I’ll try to do a quick one hopefully.

So I’m trying to understand how we should interpret the balance sheet comment because you’ve obviously got substantial inventory potential in the Delaware, but also the Eagle Ford inventory is going up and now you’ve got the Rockies and – I guess the Cana is audited [ph] as well.

Should we think of you spending your cash like old Devon or should we think about you starting to use your balance sheet to accelerate the overall pace.

I know you’re not ready to give details specifically yet, but just high level how should we think about activity roles?.

This is Vince, Doug. My first observation is while we have this growing resource inventory, we also have a lot of growth in cash flow. So when you look at 2015 with the free cash flow thrown off by the Eagle Ford over and above the capital requirements and by our thermal projects, we’ve got a lot of capacity to invest in this expanding inventory..

And Doug, we’re in a position now – the reason we’re so excited about where we are as a company frankly, we’re in a position now where we think we can grow our oil productions which is obviously our highest margin product by 20% of more for a considerable period of time while living within cash flow.

And with a $9 billion debt level, we’re probably at a fairly appropriate place for us to be.

And we haven’t been in the position in the past few years of being able to grow that kind of production which – and the important part of it is of course is that we’re also commensurately growing our cash flow per share without ramping up debt or summoning [ph] bunch of equity out the door. And that’s pretty exciting position for us to be in.

And that kind of growth rate for company our size I think stacks up pretty well..

Yes, a big change from six months ago for sure [ph]. My follow up real quick is ownership in the GP, just a big picture of comments there in terms of – 70%, it just seems there’s no need to really have that big of a position. I’m just curious as how you’re thinking about that and all these matters [ph]. Thank you..

Yes, that’s turned out really well for us. As you know, as we said, we put those assets in at about $4.8 billion worth [indiscernible] today. So there’s been a huge amount of accretion and it’s a strategic asset for us.

We’ve always wanted to keep control of those assets or have some influence over those assets because they’re so integral to our operations.

And we think there’s going to be a lot of value accretion at the EnLink level over the next few years not only from a bunch of really exciting ideas that are – the management team at EnLink has but also through the continuation of the dropdowns from the general partner and also from Devon.

And you’ll recall we’ve given a right of first offer to EnLink to purchase the expanded access pipeline in Canada when it’s complete. So we’re going to see a lot of growth. Now having said that, you’re absolutely right that they’re – we got a larger position today than we ultimately need to control. But that’s not lost [ph] on us.

We always look at ways to realize that. But frankly, we got to do something that is creative and innovative, Doug, because just selling a bunch of units and paying a lot of tax isn’t the way to do it. So we’re really actually excited about that position and the continued growth, but we’ll always keep our eye on that..

I appreciate the answers. Thank you..

Operator, we’re ready for the next question..

Great. Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is open..

Thank you. Good morning. You touched on Canadian oil realizations earlier but I wanted to ask on U.S. oil realizations which looks like they widened out a bit.

I assume some of that is adding condensate in Eagle Ford but I wanted to see how you think your differentials will fall out as we go forward both on the condensate front of Eagle Ford and then if you expect any bottlenecks in the Permian both from a midstream ability to get oil out and then also if there are any changes in your gravity in related realizations of the Delaware Basin..

Yeah, this is Darryl again. Let’s first take the Permian. We have seen differentials widen there since the end of last year into the first quarter where differentials both for West Texas sour and West Texas sweet were about $3.50. Fourth – or the second quarter this year looks like that’s going to be closer to $8 as driven by a couple of facts.

We’ve just been increased production out of the Permian Basin, plus there were some refinery maintenance that extended longer than was anticipated, about three weeks. That’s caused a bottleneck and a buildup of supply.

All of that should be relieved by the end of this quarter as we have another 350,000 barrels a day of pipeline capacity coming on stream – 50,000 is an expansion of the longhorn system that was put in place last year; 300,000 of that is BridgeTex. So when you add all of that capacity, that gives you about 5.6 million barrels of export capacity.

There’s about 400 million, I guess, of refining and production out there that’s around 1.5 million. So right now, we think the differentials while they’re $8, that’s going to narrow somewhat less than 250 as we go through the rest of the year. So we feel pretty good about that.

As we look at differentials in the Eagle Ford, our average gravity in Eagle Ford is about 52 degrees. First month that we had that asset, our net differential of WTI was about $7. We expect that to continue to be volatile as more of that type of crude is produced. But we think that’s going to be volatile in a range of about $6 to $12 of WTI.

That should work itself up. We think based on the projects that are ongoing in terms of splitters that will allow some of that lighter end product to be split out. In the next board, we think that differential will narrow down to the $6 to $8 range as we go forward. All of these are things that we have anticipated when we made the acquisition.

Our view still hasn’t changed..

Great, thank you. That’s helpful.

And then just thinking in the 2015, your comments on increasing activity again particularly on the Permian Basin, what are you doing to mitigate the cost inflation and what level of cost increases are you expecting or able to withstand when you think about that in CapEx and activity levels?.

Well, the economics on these plays are pretty robust. So although the plays could handle higher CapEx, we do a lot of work to avoid that situation obviously.

And we have just actually finished for this year and just recently our rebidding [ph] of all our stimulation work for the year were able – we have very good relationships with the key vendors, have had them over multiple years. We were able to avoid any significant price increases. That’s going to be basically flat in 2014 versus 2013.

And we anticipate that these type of relationships are going to help us significantly in the future. I can’t predict exactly what 2015 is going to look like but when you think of 2014, it’s already had rapidly increasing activity in the Permian. But there is at the same time a lot of additional capacity coming into the Permian.

So I don’t think we’re going to have a significant issue there..

Great, thank you..

Operator, next question..

Your next question comes from the line of Subash Chandra from Jefferies. Your line is open..

Yeah, hi. I just want to confirm that Eagle Ford guidance did not include Lavaca County..

It does include Lavaca County. That includes our entire Eagle Ford position, the 17,000, 18,000 which is what we originally got into also..

Right, okay. Got it, okay. And the second one on the Permian and Bone Springs and it looks like it’ll be a Bone Spring heavy program.

What sort of initiatives are there or potential for more water recycling out in the Delaware and what are sort of the technical challenges of doing that, if any?.

Yeah, probably one of the biggest challenges that we have is – and you can get an idea from the map that we included in there, but our acreage is spread out throughout DeWitt and Eddy County. So to the degree that we have contiguous position that has sufficient scale, that allows us to get into where water recycling can work more efficiently.

And we’re working through that right now. We’re already doing that in the South Midland Basin as we speak and we’re looking for opportunities to expand that into the Delaware Basin..

And just along those lines, some of these other horizons, Leonard, et cetera, are they dryer than the Bone Springs –.

Well, we have included in our account essentially the oil areas of each of these because these are the ones that we think are economic. So I know these are – with Leonard, I think some of the industry competition has been talking about wells or drilling in the Leonard and we’re right in and amongst those wells.

But frankly, we have as good, if not, better acres positioned. Some of the other people are talking about it. So we feel very good and actually, the Wolfcamp extends further to the west than we have outlined on the map but we’ve just really highlighted what we think is the oily portion of the Wolfcamp on that map.

So, no, these are essentially – these are really oil opportunities that have strong economics right now..

Okay. I guess I was referring in terms of dry, in terms of not having quite as much formation water as the conventional targets like Bone Springs..

No significant difference that I’m aware of but I may have to research that a little more. But I’m not aware of any significant changes..

Okay, great. Thank you..

Your next question comes from the line of Jeffrey Campbell from Tuohy Brothers Investments. Your line is open..

Thank you and good morning..

Good morning, Jeff..

Good morning..

I wanted to ask – kind of jump to the Powder River.

How contiguous is your position there? And along with that, do you have multiples on exposure on some of the acreage or do the frontier in the Parkman and Turner tend to occur individually on discrete locations?.

We have acreage throughout Campbell County but we also have some very nice positions that our contiguous in that area. To give you an idea, we have so far been what I would consider appraisal mode – appraising areas throughout Campbell County. Now we are in the position into Parkman and to a large degree also into Turner.

But we’re going to go into full development mode on those formations. And so what you’re going to see from us in the future is better economic – overall economic results as we can focus on development and get our costs down, get our EURs up even more consistently. So we’re seeing outstanding results.

And I can tell you that our program in the last quarter really delivered good results and you’re going to see a continuous movement in that direction as we get out of the mode of appraising our entire acreage position and get into the mode of focusing on the most economic development areas..

So just to follow up on what you just said, as you go into development mode, will you start to see a significant rise in rigs as we’re going to see in Delaware or does there still need to be some more work done before you –.

We think the opportunity is there. We’re going to have three rigs working right now. We want to walk before we run, I guess you’d say. But there’s certainly opportunity to raise the rig count in the future. But we’re going to see how these developments go.

And if they work out the way we think they’re going to work out, the opportunity is certainly there to raise the rig count in the future..

Great. And if I can ask just another quick question.

Can you tell me what your current well spacing assumptions are for your 2015 production projections in Eagle Ford?.

There are various well spacing assumptions depending on exactly where the wells are located throughout our acreage position. They vary on the order of 40 acres to 80 acres for the average about 60-acre spacing..

Okay, great. Thank you..

Okay. Well, folks, we’re sure on top of the hour and if there are any other questions, don’t hesitate to call us. We’ll be around all day. And just before signing off, let me leave you with just a few takeaways from today’s call. First, I think we’ve done an excellent job of improving our portfolio on a very short period of time.

Devon’s emerged with a formidable portfolio that’s on track to deliver multi-year growth production – oil production growth in excess of 20% while generating free cash flow. And as evidenced by our Q1 results, our pursuit of high margin production is significantly expanding our margins and profitability.

And finally, the resource potential associated with our world-class Permian position continues to get better with time and is clearly a cornerstone growth asset for Devon. As I mentioned earlier, as I look ahead, I’ve never been more excited about the future prospects for Devon.

Even with all of the exciting changes, our approach to the business remains unchanged. We will continue to aggressively pursue our top strategic objective of maximizing shareholder returns by optimizing long term growth and debt adjusted cash flow per share.

So we look forward to talking with you again at the next call and thank you very much for joining us today..

Ladies and gentlemen, this concludes today’s conference call. You may now disconnect..