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Devon Energy Corporation (NYSE:DVN)

Q1 2013 Earnings Call

May 1, 2013 11:00 AM ET

Executives

Vince White – SVP, Communications

John Richels – President and CEO

David Hager – EVP, Exploration and Production

Jeff Agosta – CFO

Analysts

Doug Leggate – Bank of America Merrill Lynch

Charles Mead – Johnson Rice

Bob Brackett – Bernstein Research

Dave Kistler – Simmons & Company

Brian Singer – Goldman Sachs

David Tameron – Wells Fargo

Operator

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. This 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.

Vince White

Thank you, and welcome everybody to Devon’s first quarter earnings call and webcast. Today’s call will follow our usual format. I’ll cover a couple of preliminary items, and then our President and CEO, John Richels, will provide his comments. Following that, Dave Hager, the Head of Exploration will provide an operations update, and then Jeff Agosta, our CFO, will finish with a review of our financial results, as well as some specific guidance for the upcoming quarter.

After Jeff’s discussion, we will have our Q&A session, and we’ve got Darryl Smette, the head of marketing midstream and supply chain with us today to help in the Q&A. We’ll conclude the call after about an hour, but as usual, the Investor Relations team will be available for any follow-up for the rest of the day.

During the call today, we’ll make some minor changes to our forward-looking estimates based on the actual results for the first quarter and our outlook for the remainder of the year. However, we will not be issuing a revised 8K because our outlook for the remainder of the year does fall within the ranges that we provided in the former 8K filed in February.

To access a comprehensive summary of our current guidance, you can go to Devonenergy.com and click on the guidance link found within the Investor Relations section of our website.

Please note that all references today to plans, forecasts, expectations, and estimates are considered forward-looking statements under US securities law and are subject to a number of assumptions, risks, and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance, and to see a discussion of the risk factors relating to these estimates, you can reference our various filings with the Securities and Exchange Commission.

Also in today’s call, we’ll reference certain non-GAAP performance measures. When we use these measures, we’re required to provide the related disclosures and they can be found on Devon’s website as well.

Before I turn the call over to John, I want to briefly comment on the 1.9 billion non-cash asset impairment charge taken during the first quarter, which resulted from a full-cost accounting ceiling test. The fact that we have an impairment charge in this quarter, in spite of stronger gas prices, seems counterintuitive at first glance. However, when you examine the mechanics of the ceiling test, it begins to make sense.

In the second quarter of last year, several of our gassy large cap piers that are on the full cost method of accounting took significant impairment charges because of declining gas prices. However, Devon’s relatively large oil and NGLs component and our reserve base protected us from having a write-down in last year’s second quarter, and reduced the magnitude of our write-downs in the second half of last year.

In the first quarter of this year, weakness in US NGLs prices and Canadian oil price realizations removed some of the cushion that was previously provided. When taken in aggregate, including our first quarter charge announced today, all of the large cap companies utilizing the full-cost method have taken write-downs of similar relative magnitude. The impairment charge, just as a reminder, the impairment charge has no impact on cash flow, cash balances or our credit agreements, and is certainly not indicative of the future cash flows we expect to generate from our assets.

When you exclude the asset impairment charge and other items analysts typically exclude from estimates, our non-GAAP earnings and cash flow for the quarter were $0.66 and $2.85 per share on a diluted basis, respectively. Higher than forecasted production and lower pre-tax costs were the key drivers that allowed us to comfortably exceed Wall Street’s expectations for the quarter.

With those items out of the way, I’ll turn the call over to John Richels.

John Richels

Thank you, Vince, and good morning, everyone. In the first quarter, we delivered very solid operating results across all of our core development assets. The conversion of our portfolio mix to a higher oil weighting remains on track and that’s evidenced by the strong growth in oil production during the quarter. More importantly, the projects driving this growth are delivering very attractive rates of return. So now, let me just go over a few highlights.

During the first quarter, we increased company-wide oil production 8%, compared to the last quarter, and 14% higher than the first quarter of 2012. This growth was led by our US oil production, which increased 23% year-over-year, driven largely by continued success in the Permian Basin. With the aggressive transition of our North American onshore portfolio mix, oil and liquids production has now reached 41% of total volumes, which is up from 30% just a few years ago.

These products now account for two-thirds of our sales revenue. We’ve also made important progress in de-risking our Mississippian and Rockies oil acreage with impressive results during the quarter, providing good visibility to the next leg of oil growth at Devon. You’ll hear more about both the Mississippian and the Rockies oil results from Dave in just a few moments.

With the recent upswing in pricing, we have meaningfully added to our oil and gas hedge position for this year and next year. This includes attractive basis swaps for our Canadian heavy oil production for the remainder of this year. We also enhanced our margins during the quarter by controlling costs. In fact, pre-tax cash costs per BOE actually declined 4% from the prior quarter.

And finally, in March, we announced a 10% increase in our cash dividend. This is the eighth time we’ve increased our dividend since 2004, and extends a long history of returning cash to shareholders through share repurchases and dividends. Of course, our balance sheet remains in excellent shape with a net debt-to-cap ratio of only 22% and $6.5 billion of cash on hand.

As we have previously discussed, $6.1 billion of our cash resides in foreign subsidiaries and there are some tax ramifications associated with the repatriation of that cash to the US. However, recent changes to our tax position now afford us the opportunity to immediately repatriate approximately $2 billion of our foreign cash with minimal additional tax. Jeff will speak to this in more detail later in the call.

One of the most discussed items in the industry right now is the improvement in natural gas prices with both the current Henry hub trading month and the longer dated strip now above $4 per MCF. The relative strength in natural gas prices is attributable to both the increase in heating demand from a late winter, along with evidence that the growth in US natural gas supply is beginning to slow significantly. These factors have helped reduce gas storage levels to just below the trailing five-year average.

The recent uplift in natural gas prices could have a significant impact on our financial results in upcoming quarters. While the improved sentiment around gas prices is certainly encouraging, we’re not modifying our 2013 capital plans at this time. Even with our natural gas assets being located across some of the lowest cost shale plays in North America, returns continue to be more attractive on the oil and liquids rich side of our portfolio versus dry gas drilling.

In addition to improving cash flows from higher natural gas pricing, we also expect to benefit in the upcoming months from improved price realizations on our Canadian oil production. For the past several quarters, Canadian oil price realizations have been very volatile and have averaged well below the historical range, due to tight regional supply and demand dynamics.

While we expect price volatility to persist for the next 12 months, we’ve recently seen a big recovery in Canadian heavy oil price realizations. Western Canadian Select blended pricing has dramatically improved from a low of approximately 50% of WTI in mid January, to as high as 85% of WTI in recent weeks. This improvement in Canadian oil pricing is in response to increased takeaway capacity and the delay in the startup of new production from Exxon’s curl project.

As with changes in natural gas pricing, our leverage to higher Canadian heavy crude pricing is quite meaningful. In spite of the clear visibility of improving cash flows, Devon’s valuation remains at a meaningful discount to our North American onshore peers. As we discussed in our last call, we are examining and considering any and every option to highlight unrecognized asset value to the market and bring that value forward for our shareholders.

However, any action we take must create sustainable long-term value for our shareholders. Keep in mind, each of these potential alternatives has unique complexities that require careful consideration. They include operational complexities, regulatory issues, contractual obligations, relative asset valuations, and tax implications, just to name a few.

As we discussed last quarter, one option being evaluated is the creation of a midstream master limited partnership. We’re nearing our – the completion of our evaluation and we expect to reach a final go/no-go decision before the end of this quarter. Pre-offering rules prohibit us from providing any additional information at this point.

In addition to the midstream MLP, we are continuing, in earnest, the review of several additional potential actions and expect to complete these evaluations by year end. So to sum it up, we continue to successfully execute our business plan, as evidenced by our solid quarterly operating results and, specifically, by the continuation of strong oil production growth.

Our continued success in the Permian, the Mississippian trends, and the Rockies has enhanced the visibility of our long-term oil and liquids growth profile. Our balanced asset portfolio provides our shareholders high margin oil growth and a significant option value on improving natural gas prices from our vast inventory of undrilled locations in the high-quality natural gas plays. And, finally, we’re committed to optimizing shareholder returns and are evaluating every option to unlock value in our company.

And with that, I’ll turn the call over to Dave Hager for a more detailed highlight of our details.

Dave Hager

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 $1.5 billion, in line with our previous guidance. Keep in mind, our first quarter expenditures will be the high point for the year due to our winter programs in Canada and the declining activity levels in the Barnett. We fully expect to be within the full year guidance range provided in our February 8K filing.

As John indicated earlier, our first quarter capital program was centered on our highest margin oil and liquids opportunities and generated positive results. We’re off to a good start this year and the solid year-over-year oil and liquids production growth in the Permian Basin, Jackfish and Cana. We also continue to move forward with the evaluation of de-risking of our various emerging plays.

Let’s take a closer look at some of the first quarter highlights. Starting in the Permian Basin, our Permian Basin production averaged a record 68,000 barrels of oil equivalent per day in the first quarter. Looking specifically at our Permian oil production, it grew 24% over the same period of last year, with wide oil accounting for 60% of our Permian volumes.

In the first quarter, we ran 29 operating rigs focused on Permian oil development opportunities. As we told you in February, we had a large number of wells awaiting completion at year end, which was a result of higher activity levels that began in the fourth quarter of last year.

We are currently working through these well completions and expect to see strong second quarter oil production growth in the Permian Basin of roughly 15% sequentially, and will continue to deliver strong growth throughout the remainder of the year. Overall, we are on track to grow basin-wide oil production nearly 40% in 2013.

A key driver of our Permian oil growth continues to be our Bone Springs horizontal program in New Mexico. We currently have 10 operating rigs working in the play. In the first quarter, we brought 20 Bone Spring wells on line, with average 30-day IP rates of 590 barrels of oil equivalent per day, of which, more than 70% was light oil. While the majority of our activity in the area is focused on our Bone Springs program, we also have an ongoing Delaware program targeting light oil.

In the first quarter, we tied in four new Delaware horizontals, highlighted by the Caswell 23-fed DH that had a 30-day IP rate of 440 barrels of oil equivalent per day, including 360 barrels of oil. Our combined drilling inventory in the Bone Springs and Delaware currently represents over 1,300 remaining locations, and more than 300 million barrels of net risk resource potential to Devon.

Now shifting to our JV with Sumitomo, exploration drilling continues across the partnership’s 556,000 net acres on the eastern flank of the Midland basin and along the Eastern Shelf. In the first quarter, we drilled eight wells across our multi-county position targeting the Cline Shale. We have data on roughly 30 horizontal wells completed by Devon and industry, to date.

The results vary widely, from 30-day IPs ranging from less than 50 BOE per day, to over 800 BOE per day. We believe that drilling without the benefit of 3D seismic is contributing to the variability in results. We are in the process of acquiring 3D seismic in the area and expect to begin incorporating our findings into our program later this year.

In addition, we continue to experiment with different completion techniques and landing zones in an effort to improve results. In the second quarter, we will begin drilling on our first five-well pad in Sterling County, with an eye towards gaining operational efficiencies and reducing costs.

Later this year, we also plan to test a horizontal Wolfcamp potential on a portion of our Cline acreage. Keep in mind, our operation is spread over a seven-county area encompassing approximately 5,000 square miles and we are still in the early stages of evaluation.

We continue to see good results from our five-rig program in the Wolfcamp Shale in the Southern Midland Basin. During the first quarter, we spun 18 new horizontal Wolfcamp wells, but because of timing issues related to pad drilling, only four were brought online. These four wells were tied in with 30-day IP rates that support our price for the area with an EUR of 500,000 barrels of oil equivalent per well.

To date, we have brought online a total of 30 operated Wolfcamp Shale wells and have established approximately 800 undrilled locations in this oil resource play. At this point, we are confident characterizing our Southern Midland Basin Wolfcamp shale as a highly economic, repeatable development play.

In summary, Devon’s 1.3 million net acres in the Permian represents one of the largest and best quality acreage positions in the industry. We continue to be one of the most active Permian drillers and we expect to grow our basin-wide oil production nearly 40% in 2013. With our inventory of thousands of undrilled locations remaining in the Bone Springs, the Delaware, and the Wolfcamp Shale, we expect high growth rate from our Permian oil properties for many years to come.

Shifting to our thermal oil projects in northeastern Alberta, aggregate first quarter production from our two Jackfish projects averaged approximately 54,000 barrels of oil per day net of royalties. Jackfish 1 accounted for 33,000 barrels per day of this total and continued this trend of excellent plant reliability and efficiency. The exact timing of payout at Jackfish 1 continues to fluctuate with changing heavy oil prices and differentials, but our current expectation is for payouts to occur sometime in the second half of this year.

Also at Jackfish 1, we’re testing a variety of productivity enhancements, including the use of solvents and natural gas co-injection. Our first pilot program on these new fronts kick off in the first quarter. If successful, these technologies will likely apply to our other thermal oil assets. We will be monitoring the results of these pilot programs over the course of the year to determine the degree of success and the optimal path forward regarding their use at other locations.

At Jackfish 2, first quarter production increased to an average of 21,000 barrels per day net of royalties. We have completed the wells on an additional well pad at Jackfish 2. Insulation of pad facilities will continue through the summer, followed by commissioning and first steam scheduled for late in the fourth quarter. At Jackfish 3, we’re moving forward on schedule and on budget, with approximately 60% of the project now complete. This puts us on track for a startup around year-end 2014.

At Pike, we wrapped up our winter drilling program during the first quarter. We drilled 34 stereographic core wells and acquired some 55 square miles of seismic. This program essentially completes the evaluation of the first phase of the Pike development, confirming a high-quality reservoir similar to that of our Jackfish projects.

We expect to receive our regulatory approval on Pike around year-end and we continue to work with our partner on the design of the 105,000 barrel per day Pike 1 development. We operate Pike with a 50% working interest, with BP owning the other 50%.

As a reminder, we expect our portfolio to sag the assets to drive Devon’s net thermal oil production to at least 150,000 barrels per day by the end of the decade, representing a compound annual growth rate in the high teens.

Also in Canada, we told you last quarter about our plans to move forward with a development project in the Ferrier corridor area in Western Alberta. This is an area where Devon has roughly 240,000 net acres prospective for the cardium oil and liquid-rich zones, including the glauconite. The first stage of development is focused on about a third of our acreage position, where Devon has an inventory of more than 200 locations, with net resource potential in excess of 100 million barrels of oil equivalent.

Liquid production from its first phase of the development is expected to account for roughly 50% of total production. As a result, we’re constructing a gas processing facility with an inlet capacity of 100 million a day and liquid processing capacity of approximately 13,000 barrels per day. Construction of the facility began in March and is expected to be complete by mid 2014. We will begin ramping up our drilling activity late this year with a six-rig program planned for the fourth quarter.

Moving now to the Cana Woodford shale in Western Oklahoma. In the first quarter, we had 14 operated rigs running. We continue to achieve outstanding results from our focused drilling program in the liquid-rich core. During the quarter, we brought 28 operated wells online with average 30-day IP rates of 5.5 million cubic feet equivalent per day, including 470 barrels of liquids per day. These results continue to rank among the best in the play, to date, and continue to exceed our type curve expectation.

First quarter production averaged 340 million cubic feet equivalent per day, a 26% increase over the year-ago quarter. Cana’s first quarter production growth was led by oil and NGL growth of 78% year-over-year, to 5,000 barrels of oil and 18,000 barrels of natural gas liquids per day. Shifting to the Barnett shale in north Texas, in the first quarter our liquids-rich focus drilling program in the core of the play continued to generate competitive returns.

First quarter net production averaged 1.4 BCF equivalent per day, a slight increase over the previous quarter. Liquids production increased 5% year-over-year to 55,000 barrels per day. Our full-year production guidance assumes a 4% year-over-year decline for the Barnett, but we continue to be impressed with the performance of our base production.

Our efforts to mitigate the declines through initiatives such as reducing line pressures and increased use of automation are paying dividends. With their recent strengthening in natural gas prices, we expect to generate nearly 600 million of free cash flow in the Barnett, in 2013. As John mentioned, we continue to monitor the gas markets very closely. Should the outlet – outlook for gas prices continue to improve, we can easily shift activity to the Barnett and take advantage of the thousands of rift locations we have in our undrilled inventories.

Finally, to the final development drilling area I’ll cover today, in the Granite Wash area we’re continuing to see solid results. We brought seven operated wells online during the first quarter, including two operated Hogshooter wells with an average 30-day production rate of 1,250 barrels of oil equivalent per day, including 1,100 barrels per day of oil and liquids.

Subsequent to the quarter end, we tied in another Hogshooter well, the lot 1-9, located in Wheeler County. The lot 1-9 has been online for just 15 days and has averaged 2,500 barrels of oil equivalent per day, including nearly 2,000 barrels of oil per day.

On the exploration front, from our 600,000 net-acre position in the Mississippian to north central Oklahoma, we have some very encouraging results to report. In the first quarter, we brought 24 wells online, bringing our total operated well count in the play up to 53 producing wells. To date, the majority of our activity has been focused in Noble, Payne and Logan counties, within the joint venture with Sinopec, in which they carry the majority of our capital cost.

At quarter end, we had approximately 71 wells in various stages of completion or tie-in, due to the timing of pad drilling and related infrastructure build-out. It is important to note that because of constraints in the gas-gathering infrastructure and maintenance restrictions, production rates for many of our new wells have been limited. However, even with the constrained flow rates, our results from this play continue to support or exceed our target economics.

Recently, we have seen several wells that have been producing between seven and 30 days, with rates from 600 to over 1,100 barrels of oil per day. That is not barrels equivalent. That is the oil production only. In addition, these wells produce significant volumes of high BTU gas. To date, we are also seeing a higher component of propane and heavier liquids in the NGL barrel, as compared to other liquids-rich plays.

Our recent well results confirm our belief in the important of 3D seismic in the area. With the incorporate – with the incorporation of 3D seismic into our geological modeling and our selection of drilling locations, we are beginning to see significant improvement in well results.

Our recent success has confirmed our plans to concentrate our activity in areas where we have incorporated 3D seismic into our program. In addition to the benefits of 3D seismic, we have strong evidence our improving completion techniques are resulting in higher EURs.

In summary, strong results from the Mississippian trend confirm our belief that this area will provide the next leg of large-scale – large scale highly economic oil growth for Devon. And finally, our Rockies oil exploration program delivered encouraging results in the first quarter. Within our Powder River Basin acreage in northeast Wyoming, we brought five oil wells online during the quarter targeting the Turner, Frontier and Parkman formations.

Initial 30-day production from these five wells averaged 540 BOE per day. Following the end of the quarter, we commenced production on two additional high-rate oil wells. After a few weeks of production, these wells, targeting the Parkman and Turner, were averaging 1,100 barrels of oil equivalent per day, including 960 barrels of oil. Our four-rig program in the Rockies will focus on exploiting our success in the powder river throughout 2013. To date we have identified approximately 600 risk locations across these three formations and we expect this inventory to grow as we continue to de-risk this emerging opportunity.

So, in summary, our 2013 capital program is off to a great start. With solid production results in our cornerstone areas and a significant inventory of emerging oil opportunities, we are poised to deliver solid oil and liquids growth in 2013 and beyond. With that, I’ll turn the call over to Jeff for a financial review and outlook, Jeff.

Jeff Agosta

Thanks, Dave and good morning, everyone. Today, I would – take you through a brief review of the key drivers that shaped our first quarter results and, where called for, provide updated guidance.

Beginning with production, our first quarter production was very strong, averaging 687,000 barrels of oil equivalent per day. This exceeded the upper end of our guidance range by a few thousand barrels per day. Solid execution across all of our core development regions drove the strong performance. Most importantly, on the oil side of our business, we again delivered excellent growth.

For the quarter, oil production averaged 162,000 barrels per day, setting an all-time high from our North American asset base and coming in at the top of our guidance range for the quarter. Led by robust growth in the Permian Basin, our US oil production grew 23% compared to the first quarter of 2012.

Looking to the second quarter, we expect growth in the Permian and Mississippian trend to boost total oil production by about 4% sequentially, to a range of 163 to 173,000 barrels per day. NGL production for the second quarter will be essentially flat with the Q1, due to the timing of bringing on wells in our liquids-rich plays.

After taking into account expected declines in natural gas, we expect total company-wide production in the second quarter on a barrel of oil equivalent basis to range between 670 and 690,000 BOE per day. For the second half of the year, oil and liquids growth will accelerate as a result of pad tie-ins and a plan expansion at Cana, a plant expansion in the Barnett, and the impact of the ramp-up in the Permian and Mississippian trend.

Moving to price realizations, as John mentioned earlier, we expect Canadian oil realizations to be volatile, but to improve going forward. Although our realized oil price in Canada averaged only 43% of the WTI benchmark during the quarter, this result was right in line with the guidance we provided. The weak pricing was driven by abnormally high crude storage levels carried over from late 2012, due to down time at multiple refineries and restricted flow rates on key export pipelines.

These temporary bottlenecks have improved as we have moved into the second quarter. In fact, the Western Canadian Select differential in April narrowed to $23 below WTI. In the May contract, it tightened even further to a discount of only $14 per barrel. As result of this improved pricing, we now expect our second quarter Canadian oil price realizations to range from 55 to 65% of WTI.

Looking briefly at our hedging activity, since our last update at year-end, we have added oil hedges. For the balance of 2013, we have entered into contracts to hedge 135,000 barrels per day, which is just under 80% of our forecasted oil production. Of this total, 70,000 barrels per day are swapped at a weighted average price of $100 per barrel. The remaining 65,000 barrels per day utilizes costless callers, with a weighted average ceiling of $112 per barrel and a floor of 90. Additionally, we have taken advantage of the improved outlook in Canadian heavy oil pricing to add regional basis swaps.

For the remainder of the year, we have 35,000 barrels per day swapped at a discount to WTI of $22 per barrel. The recent rise in natural gas prices has also provided us the opportunity to add to our natural gas hedge position.

For the remaining three quarters of 2013, we have protected 1.7 billion cubic feet per day, representing approximately 75% of our expected natural gas production. Of this total, roughly one BCF per day is swapped at a weighted average price of $4.09. Of the remaining 700 million cubic feet per day utilizes costless callers, with a weighted average ceiling of $4.19 and a floor of $3.55.

For 2014, we now have 900 million cubic feet per day hedged with a weighted average floor price of $4.34. For more details on our hedging position, please visit the guidance section of our website that Vince referenced earlier.

Now, turning briefly to our midstream business, our marketing and midstream operations generated $125 million of operating profit in the first quarter, enhancing our company-wide margins by more than $2 per BOE. Improved natural gas prices and strong cost management helped us exceed the high end of our implied guidance range and increased operating profit by 12% compared to the first quarter of last year.

With a more favorable gas price outlook for the rest of the year, we are well positioned to achieve our full-year forecast of 425 to 475 million midstream operating profit.

Now looking at expenses, in the first quarter, we continued to do a good job controlling costs. Costs in several categories were lower than guidance, most notably, LOE and G&A.

In aggregate, our total pre-tax cash costs were $14.54 per BOE. Or about 4% lower than last quarter. This result is especially impressive given our focus on higher margin oil production, which is generally more expensive to produce. Having achieved significant scale in our core operating areas, coupled with our consistent focus on cost management, we are positioned with one of the better cost structures in the industry.

So moving to the bottom line, our non-GAAP earnings were $0.66 per share, exceeding Wall Street expectations by 20%. This level of earnings translated into cash flow before balance sheet changes of $1.2 billion or $2.85 per share, also exceeding the street’s expectations.

We exited March with cash and short-term investments of $6.5 billion and a net debt to adjusted cap ratio of 22%. Of this $6.5 billion of cash, about 6.1 billion continues to reside in foreign subsidiaries. As we have previously discussed, we’re able to move the foreign cash to Canada without incurring additional taxes. In fact, by mid-year, we will have moved approximately $500 million to Canada to help fund ongoing activity.

Conversely, moving the foreign cash to the US can result in additional taxes, depending upon our tax position at the time. However, based on our recent activity levels and evolving tax attributes, it appears the tax NOLs, in conjunction with our foreign tax credits, can be used to offset taxes due to the repatriation of our foreign cash back to the US. As a result, we will be moving approximately $2 billion of our foreign cash back to the US with minimal additional taxes.

As we move through the year and get additional clarity on our future tax position, we believe there may be the potential to bring back another sizeable amount of cash to the US later this year or in 2014 on a tax-efficient basis.

Once this cash becomes available to use within the US, our first action would be to immediately repay outstanding commercial paper borrowings. Beyond that, we will allocate capital as we always have by assessing the relative attractiveness of E&P expenditures versus share repurchases and debt repayments, in an effort to optimize growth and cash flow per share adjusted for debt.

So with that, I’ll turn the call back over to Vince for Q&A. Vince.

John Richels

Thanks, Jeff. As a reminder, during the question-and-answer session, we’ll ask each participant to limit their question to one initial inquiry and one follow-up. And, with that, Operator, we’re ready for the first question.

Question-and-Answer Session

Operator

(Operator instructions). Your first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Your line is open.

Doug Leggate – Bank of America Merrill Lynch

Thank you, good morning, everybody. Hopefully two – two quick ones. Jeff, on the repatriation of the cash, could you just help us why you don’t have a little more conviction in going directly to share buybacks with the cash given what your share price is? And I’ve got a follow-up.

Jeff Agosta

Well, the immediate thing to do is to repay our commercial paper, we’ve got a large amount of that, over $3 billion of commercial paper. We’ll assess the viability of a share buyback in due course, like we normally do.

John Richels

Doug, it’s John. Let me add one thing. One of the points we’ve been trying to make for some time is we haven’t constrained the types of things we thought were proper allocations of capital just by where the cash resided and you’re very familiar with this, not everyone on the call is quite as familiar so let me take two seconds just to kind of go back to the history because you recall what we did is we got a little over $10 billion for the sale of our offshore assets.

That was about 7.9 or $8 billion after tax. First thing we did is we returned 40% of it or a little over 40%, almost 50% to our shareholders through a share buyback and since that time have been investing the remaining funds into this transition of our – our portfolio to higher oil-based properties.

So, and light oil properties. So it’s not like we haven’t been allocating that and it’s just been sitting there. I think that’s an important thing to realize. And we really haven’t been constrained in our ability to allocate that capital given the fact that there has been no negative carry between borrowings in the US and the amount that we’ve been earning on those funds offshore just because of the low-interest rate environment so I just thought I’d throw that clarification out there.

Doug Leggate – Bank of America Merrill Lynch

I appreciate that, I guess, John, in light of your efforts you’ve given your acknowledgment of where the share price is relative to where you think it should be I’m just a little surprised you’re not getting more aggressive on the opportunity to buy back your stock the these levels, I guess that’s all I’m saying.

John Richels

Well, one other thing there, Doug, is that, you know, we have – we’ve been moving down the road here on these light oil projects that we think are very – give us very, very good rates of return. And it’s early days for some of these projects. And it’s very hard to kind of move around, you know, stop pursuing that program and move to a share repurchase and back and forth so we have some large oil opportunities in this company that’s going to require significant levels of capital expenditure over the next while.

So we’ll continue to look at that and, as you know, I don’t think we’ve been shy about that at all and we’ve bought back more stock than anybody in our peer group and so we’ll continue to look at it very carefully.

Doug Leggate – Bank of America Merrill Lynch

Thanks for that. My follow-up is for David, I expect it’s for David. David, the oil rates coming out of the Mississippian line, can you just give us a little bit more help as to where you see the tight curves now in those areas particularly as you move north into the Vitruvian acreage because 600,000 barrels of oil sounds like it’s even better than some of the established players in that area and production rates would be helpful, thanks.

Dave Hager

Yeah, Doug. We’re not going to get into too much specifics on where we’re getting what rates, for competitive reasons, we’ve invested a lot of money and effort into 3-D seismic which we think has given us a competitive edge and so for competitive reasons I’m not going to discuss too much about this, but in general, we are staying with our tight curves that we have established before, we are seeing, though, obviously, some wells that are significantly above our tight curve that I highlighted in my section of the call.

This that we think is directly attributable to the 3-D seismic and the additional science we’re doing in the area. We are still saying that overall that over the life of the well, that about 40% of the production will be oil, about 20% NGLs and the remaining natural gas.

Now, early on you get a much higher percentage of the production, that is oil, and it tends to become more gassy through time. But, of course that’s a good thing because it means you get your value back more quickly.

Doug Leggate – Bank of America Merrill Lynch

All right. I’ll let someone else jump on. Thank you.

Operator

Your next question comes from the line of Charles Mead with Johnson Rice. Your line is open.

Charles Mead – Johnson Rice

Good morning, thanks for taking my question. With regards to the tax-free repatriation, I’m curious, is this – has there been some movement on the regulatory front, or is this more a function of sharpening your pencil and getting creative with legal structures? And when you talk about the possibility of repatriating the additional 4 billion in a tax-efficient manner, I’m curious, does that mean 0% or does that mean, you know, below some threshold of, you know, X percent?

Jeff Agosta

Charles, this is Jeff. Just to clarify when we talk about the first 2 billion being moved back we didn’t say tax-free, it’s with minimal additional taxes. You know, think in terms of mid single digits percentages of cash taxes.

Charles Mead – Johnson Rice

Got it.

Jeff Agosta

And it is – Devon fact-specific. There were no regulatory changes and there are no clever legal structures being utilized. As to any amounts that we would repatriate in the future, of course, we would want to make sure that it was a tax-efficient repatriation. So it would – it’s not likely to be the full 4 billion but it could be another sizeable amount, similar to what we’re doing currently. But that is, again, going to be Devon fact-specific and it’s going to depend on our future tax profile.

Charles Mead – Johnson Rice

Got it, thank you, Jeff, and if that counts as one question, I’d like one follow-up, if I could with Dave. Dave, I was wondering if you could give a little more detail on the horizontal Wolfcamp wells that you drilled along the lines of the length of the laterals, where in the zone that you are – that you’re landing those and if you could, offer a comparison with what you’re doing in the Delaware basin with Bone Springs in Delaware both in terms of how mature the plays are and where you think they might sort out on attractiveness.

Dave Hager

Well, they’re both very attractive plays to start with. They both have strong rates of return, whether you’re talking about the Delaware or the horizontal Wolfcamp play. We have been targeting our wells in the horizontal Wolfcamp play to be on the order of 7500-foot to 8,000-foot lateral length, we think that’s important for the overall economics.

We also have been landing zones – it depends a little bit geographically where you’re talking about here but we – we land more in the lower Wolfcamp but we also land some in the middle Wolfcamp as well, when we land in the lower Wolfcamp we think we’re actually communicating up to the middle Wolfcamp in many cases anyway, so but we found that to be the best and I think we’re the first company, frankly, to start landing wells in the lower Wolfcamp and led the way on that, so another example of Devon taking the lead on it.

We just have – we’re now characterizing the Wolfcamp as a development play. We have enough wells out there with a lot of repeatability of results that we’re very confident that we have, we set 800 locations in the Wolfcamp and we have 1300 locations between the Bone Springs and the Delaware, so right there over 2,000 location so that’s what underpins our growth and I can characterize them as essentially in the development mode at this point.

Charles Mead – Johnson Rice

Great. Thank you for the added detail, Dave.

Operator

Your next question comes from the line of (inaudible) with Credit Suisse. Your line is open.

Unidentified Analyst

Jeff, I was wondering if we could go over the guidance real quick. I was a little bit surprised that, you know, you guided the 670 to 690 given some of the comments in the call script. You did 687 this quarter, you guys talked about 15% of growth in the Permian on the oil side which would put you, you know, at 693 plus some, you know, momentum in the Cana as well as the Mississippian so I was just wondering if you could maybe elaborate on what some of the minuses could be as you go into Q2.

Jeff Agosta

Sure I’ll take a stab at it and let others jump in as well. It’s mostly the gas decline that causes the BOEs. I think if you look at it on a barrel of oil equivalent basis just because we’re coming off such a high percentage gas production on a BOE basis and the decline in natural gas, also the NGLs are going to be muted growth in the second quarter just due to the timing of tie-in of new well pads.

Unidentified Analyst

Okay.

Jeff Agosta

I don’t know, Dave.

John Richels

That’s exactly right. Let me take the opportunity to answer a question you didn’t ask. Some people have been saying, well, your Permian growth has been fairly flat the last couple quarters, what about your – you’re projecting 40% over the year and we are – the answer there is pad drilling.

We have for instance right now about 20 wells and we’ve been bringing on or currently bringing online within the Permian and so we’re going to be significantly ramping up our production in the second, third and fourth quarter. You saw in the quarter we drilled 19 wells, only completed four, so we’re working our way through that backlog right now, and that’s what’s going to really drive the Permian oil growth. We’ve reviewed it and we’re very confident on that growth throughout the year.

Unidentified Analyst

That’s helpful. John, I just wanted to see if you could, you know, talk about – you mentioned you’re going through the evaluation of the midstream process today. Understanding you can’t get into too many of the details I was wondering at a high-level you’re talking about some of the pros and cons and what will drive the ultimate decisions on whether to move forward or not.

John Richels

You know, we’ve got to be very careful about what we’re saying. We’ve pretty much been wood-shredded by our securities lawyers on – on this. But some of the things that we’re going through, and we’ve talked about this openly, is – is, you know, when you first look at it on the back of a piece of paper, it looks – these things – you develop a certain outlook for it and then you’ve got to get a lot of details. And some of them are specific.

We’ve got to get through all of our contracts and how they’re going to work under – if we went to an MLP and some of the operational complexities, the tax complexities and that type of thing so we’re just kind of working our way through that and I hate to hold you off on that, but we really think we will have had the opportunity to do some really detailed work as we need to with a transaction of this size and be able to come out with a – with a final goal or – go or no-go decision here by the end of the quarter.

Unidentified Analyst

Fair enough. Thanks a lot

Operator

Your next question comes from the line of Bob Brackett with Bernstein Research. Your line is now open.

Bob Brackett – Bernstein Research

Yeah, I had a question on the Barnett you talked about potentially as gas price rises you can see more incremental activity there. How long would it take you to get a supply response if you put a rig back in the Barnett next month?

John Richels

Well, if we start drilling in the Barnett we are essentially pad drilling in there, so it’s on the order of four to six months, really, before you complete the pads, all the drilling, complete all the completions on them before you even bring those wells on production and, of course, it’s important to remember we’re dealing with a very large base production in the Barnett right now of 1.4 BCF equivalent per day.

So one of the things we’re really focused on is optimizing that base production because – and that’s where I was highlighting during my comments of how we think we’re doing a good job of maximizing that base production. So that’s really frankly just as important at this point as putting more rigs back to work.

Bob Brackett – Bernstein Research

Okay. And the follow-up, do you guys have an internal view of where your share price should be?

Vince White

This is Vince. We do have an internal view and I would say that we generally believe that it’s the market’s place to set our stock price based on our performance ands and we’ve been told by a lot of participants in the market that we aren’t getting the value of the underlying assets reflected in our current share price.

Bob Brackett – Bernstein Research

And so if you have an extra $100 million to invest, do you look at basically what MPV you’d create with a drill bit versus what MPV you’d create in buying back shares, is that the logic of that thought process?

Vince White

We do model that out over time. This goes back to what John was saying earlier. We look at the expected returns or impact on cash flow per net adjusted share from incremental on the property base versus the impact of buying shares.

And while as John said we can’t really zig and zag a lot, we strapped on some large acreage positions in light oil plays, we’re having some pretty good early success in those plays and as we move forward in those they’re likely going to afford us the opportunity to invest large amounts of capital at high rates of return. So if they play out the way that we believe they will, this produces the optimum outcome.

Bob Brackett – Bernstein Research

Okay, thanks.

Operator

Your next question comes from the line of Dave Kistler with Simmons & Company. Your line is open.

Dave Kistler – Simmons & Company

Morning, guys.

John Richels

Morning, David.

Dave Kistler – Simmons & Company

Real quickly, when you talk about the Permian and the amount of capital that it can absorb over time you have done a JV and a portion of it, is something like a JV still on the table and would that potentially be why maybe production guidance remained the same for the balance of ‘13 even though Q1 dramatically outperformed and Q2 looks positioned well plus you are going to work through drilled uncompleted wells, pad drilling kicking in, in the second half, Barnett flattish, just trying to understand exactly what’s happening with guidance and then the propensity for a JV.

John Richels

Well, you know, Dave, we tend to – you know, the previous joint ventures that we did, we tended more to earlier exploration plays earlier phase plays and the reason for that is because in addition to the – just the uplift you get on an – from an economic point of view, you’re also bringing someone in at an early stage to help to defray some of the risk or help to mitigate some of these risk and you don’t always know how some of these things are working.

When you get to a play that’s more in the development stage, whether it’s the Permian or some of the other plays, at that time it becomes much more just a financing technique. And the financing from a joint venture is quite a bit more expensive than our cost of capital.

And so, you know, we haven’t – we’ve done it from an operational perspective in the past, not as a method of financing our operations because it is a more expensive way to finance those operations. So I’m not sure that these plays that are in the development stage are the right ones or at least we haven’t – we haven’t pursued that in the past.

Dave Kistler – Simmons & Company

Okay, appreciate that clarification and then maybe a little bit more specifically looking at the Powder River basin results, can you talk about length of laterals, design of the wells, et cetera, I mean obviously the results from those wells in the four-rig program are pretty darned impressive.

Dave Hager

You’re right David, this is David, the results were impressive and have really given us renewed confidence that we can have a lower risk development opportunity with a lot of locations out there. The well design, I don’t have the specifics on them, but we’re typically drilling those around 4500, 5,000-foot laterals, pretty typical for the – for the area.

And so there’s nothing particularly unique, I would say, about the drilling and the completion side. What we’ve really been able to do is just high grade the acreage significantly where from a geological standpoint where each of these plays work, and that’s the key to it so we’ve done a lot of detailed technical work to figure that out and over the course of the past year or two and now we’re starting to see the results of it.

Dave Kistler – Simmons & Company

Great, well, I appreciate the clarification, guys. Thank you.

Operator

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

Brian Singer – Goldman Sachs

Thank you, good morning.

John Richels

Good morning, Brian.

Jeff Agosta

Good morning.

Brian Singer – Goldman Sachs

In the Permian Basin in the Cline field specifically how far east have you now pushed your drilling and you mentioned there’s a decent volatility partly because of a lack of seismic, but how do your well results compare as you go east versus what you and the industry have seen from the wells to the – to the west?

John Richels

Well, we’ve drilled wells throughout our acreage position. We started off more to the southwest in sterling county, we have pushed further to the north, as far up as fisher county, as well as Noland county, so we’re testing some throughout the acreage position. But keep in mind, though, we’re testing a very, very large area, it’s about 80 by 100 miles so even though you may have a well throughout that acreage position.

If you don’t have the benefit of 3-D, that doesn’t mean you’ve necessarily landed the well and drilling horizontally in the optimum position so just having one or two wells across an entire acreage position doesn’t really confirm or condemn an area.

You need to get a lot more – and we’re seeing – we’re seeing it in the miss where the 3-Ds are important and the miss –and we think the s-D is going to be important in the Cline as well. In General, our well results have been little bit better to the southwest side so far, but it’s early on and that can change as we get more technical data and more well results.

Brian Singer – Goldman Sachs

Great, thanks. And my follow-up is with regards to asset sales and CapEx trajectory if we look at your cash flow statement CapEx for the quarter it was very similar to the last couple of quarters. Can you refresh us on CapEx trajectory through the remainder of year and how acreage acquisitions are trending so far versus what’s baked into your guidance.

Jeff Agosta

There’s about $2 million, Brian, baked into our guidance for acreage, and I would say that hasn’t really changed dramatically and we’re on track and I would say our CapEx this next quarter is going to be down a bit from – on the E and P side by about $200 million and it should trend down quarter by quarter as we go throughout the year to be at the midpoint of our guidance range.

Brian Singer – Goldman Sachs

Great, thank you.

Jeff Agosta

You bet, Brian.

John Richels

We’ve got time for one more question, operator.

Operator

Your last question comes from the line of David Tameron with Wells Fargo. Your line is open.

David Tameron – Wells Fargo

Hi, glad I made it in. Couple questions. The cash repatriation, I’m sorry, the shields on those, the tax shields, are those the same instruments you’d be using if you did hypothetically an MLP or asset sale or something along those lines. Is that like the same tax shield?

Jeff Agosta

If we did a large, a very large US-based asset sale then yes. As far as the MLP, it’s – it wouldn’t have much of an impact on that.

David Tameron – Wells Fargo

OK, thanks, that’s helpful.

Jeff Agosta

You bet.

David Tameron – Wells Fargo

And then secondly, on the acquisition – everyone talks about– Can you talk about your outlook for acquisitions, I know that’s been a constant theme floating on the markets for – for a while. Can you tell us, refresh us where you’re at on that?

John Richels

Well, Dave, on acquisitions, as you know, we – we – we’ve been pretty active over the years, may be an understatement, I guess, but we certainly haven’t been out there for the last while – you know, really acquisitions look pretty expensive over the last few years, when you take a look at acquisitions in any of the areas that we might want to be in.

I would say that our view right now, and this is not a scientific analysis, but it’s an intuitive analysis, is that we’re moving into a time when there’s more products on the market and it’s more of a buyer’s market if I can call it than sellers’ market that we’ve been going through the last few years.

We continue – we always look at things and any decision we’re going to make, though, in that regard, again, is going to be a decision on what the impact is on debt adjusted cash flow per share as opposed to investing in a large asset base, buying back our stock and doing the other things. But, you know, I think there’s – I think that we’re moving into a little different market than we’ve been in for the last while.

David Tameron – Wells Fargo

I would agree with that. Thanks, John, thanks for the caller.

John Richels

Thank you, folks, we appreciate your joining us today. And as Vince said for those who didn’t get your questions in, our Investor Relations folks will be available all day. We’re continuing – we’re excited about the execution of our business plan.

We’re moving in a direction of continuing our strong oil production growth, got great visibility of our long-term oil and liquids growth profile, and we continue to provide our shareholders with a very high margin of oil growth with significant option value on improved natural gas prices and improving Canadian heavy oil price differentials. So we will look forward to talking with you again at the next call and thanks very much for joining us.

Operator

This concludes today’s conference call. You may now disconnect.

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