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Executives

Vincent White - SVP, Communications and IR

John Richels - President and CEO

David Hager - COO

Analysts

Brian Singer - Goldman Sachs

Evan Calio - Morgan Stanley

Arun Jayaram - Credit Suisse

Hsulin Peng - Robert W. Baird

Charles Meade - Johnson Rice

Devon Energy Corporation (DVN) Q4 2013 Results Earnings Conference Call February 19, 2014 11:00 AM ET

Operator

Welcome to Devon Energy's Fourth Quarter and Year End 2014 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the prepared remarks, we will conduct a question-and-answer session. 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.

Vincent White

Thank you, and welcome everyone to Devon's fourth quarter and year-end 2013 earnings call and webcast. Today's call will follow our usual format. I'll cover a few housekeeping items and then turn the call over to our President and CEO, John Richels. John will provide an overview of our 2013 results and his thoughts on the year ahead. And then Dave Hager, our Chief Operating Officer will provide an update on Devon’s operations. Following the operations update, we will turn the call back over to John to finish off our prepared remarks with a review of our financial results and to provide some specific guidance for the upcoming quarter and for the full year 2014. After our financial discussion, as usual we’ll have a Q&A session. We’ll conclude the call after one hour and a replay of the call will be available later today on our website. The Investor Relations team will also be available after the call should we have any additional questions.

On the call today, we’re going to provide forward looking estimates for capital, production, price realizations and other important items for 2014. Later today, we will file a Form 8-K that contains our detailed estimates for the upcoming year. The guidance page of our website will contain a copy of the 8-K along with other significant forward looking estimates that we mention during the call today. To access this guidance, just click on the guidance link found in the Investor Relations section of the Devon website.

The guidance we provide today includes plans, forecasts, expectations and estimates and they are all forward-looking statements under U.S. securities law. These are of course, subject to a number of assumptions, risk and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance. You can see a comprehensive discussion of the risk factors relating to these estimates in our Form 10-K.

Also in today's call, we'll reference certain non-GAAP performance measures. When we use these measures, we're required to provide certain related disclosures. Those can also be found on Devon's website.

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

John Richels

Thank you, Vince, and good morning, everyone. 2013 was another year of strong execution and exciting change for Devon. Our oil focused drilling programs not only accomplished impressive oil production growth, but also successfully expanded margins and improved our operating cash flow. Additionally, we’ve taken some bold steps in a relatively short period of time to high grade our portfolio and improve Devon’s growth trajectory. We did this through an accretive Eagle Ford at our shale acquisition, an innovative midstream combination and the initiation of an asset divestiture program.

Now let’s briefly recap some of the past year’s highlights in a little more detail. In 2013, we had outstanding success growing U.S. oil production, our highest margin product driven by our development programs in the Permian Basin; we increased our light sweet crude production in the U.S. to 78,000 barrels per day, up 32% compared to 2012. This highly profitable U.S. oil production growth is particularly impressive considering the large base of oil production that we are [drilling] [ph] off, a base that ranks Devon as one of the largest independent oil producers in the U.S.

Our pursuit of oil production resulted in higher revenues and improved profitability as well. In 2013, company-wide oil revenue increased by 23% compared to the previous year and accounted for more than half of our total upstream revenue.

This revenue growth combined with the strong focus on cost containment improved our operating cash flow in 2013 by 10% year-over-year, significantly exceeding Wall Street estimates.

Looking beyond our reported results we also made some exciting portfolio changes at Devon during 2013. In October, we announced the strategic combination of our U.S. midstream assets with Crosstex to form EnLink Midstream. The creation of EnLink greatly improves the diversification, capital efficiency and growth trajectory of our midstream holdings. Additionally, this innovative transaction allowed us to obtain an immediate market-based valuation for the U.S. portion of our midstream business.

At the time of the announcement, Devon contributed assets valued at $4.8 billion. As of yesterday’s closing prices, our ownership interest in EnLink was valued at more than $8.3 billion or roughly a third of Devon’s market capitalization.

The combination has already resulted in an additional $3.5 billion of value or the equivalent of more than $8 per share and we expect additional value to accrue as EnLink grows and develop its assets.

And further significant transaction for us announced in late November was our acquisition of Eagle Ford assets. This transaction allowed us to secure a world-class light oil acreage position in the very best part of the Eagle Ford offering some of the highest rate of return drilling opportunities in North America. We were able to acquire these premier assets in the economic heart of the play at a price well below our current EBITDA multiple.

Given the attractive purchase price, the Eagle Ford acquisition is immediately accretive to Devon shareholders on virtually every metric including most importantly double-digit growth in cash flow per share adjusted for debt.

In conjunction with our Eagle Ford transaction, we also announced our intent to monetize non-core E&P properties both in the U.S. and in Canada. This initiative further sharpens Devon’s focus on core assets, delivering material growth rates or substantial free cash flow. This morning we are pleased to announce the sale of our entire Canadian conventional business, excluding Horn River for approximately C$3.125 billion or at current exchange rate US$2.8 billion.

This transaction values are natural gas levered Canadian conventional business at approximately 7x 2013 EBITDA. This is a substantial premium compared to our current trading multiple and is immediately accretive to Devon shareholders.

Additionally, this was a very tax efficient transaction for Devon. After adjusting for Canadian taxes and tax on repatriation of funds to the U.S. we expect net proceeds of approximately US$2.7 billion.

We will utilize these net proceeds to reduce the debt that we are taking on with the Eagle Ford acquisition and we expect to close this transaction in the second quarter. The sale to Canadian Natural is in addition to minor asset sales of other Canadian conventional assets in early 2014 of about another C$155 million. The attractive monetization of our largest divestiture properties in such a short time period is a significant step forward in the execution of our overall divestiture process.

For our remaining divestiture assets in the U.S. even before opening our data rooms we are seeing significant buyer interest. We expect to have all these asset packages on the market in the second quarter and remain confident that we are on track to finish this divestiture process by year end.

We will provide additional updates on our progress as we move throughout the year. So the New Devon has greater focus with our retained asset base in five-core development plays, three of which reside in some of the most attractive oil prone basins in North America, the Eagle Ford, the Permian Basin, and the Canadian oil sands. Each of these core oil assets represents a low risk and high margin production growth opportunity with the scale to significantly impact the results of the company our size. The retained liquids rich gas component of the New Devon is anchored by our Barnett and Anadarko basin assets, these core areas currently generate large amounts of free cash flow and provide significant gas optionality. So in aggregate, Devon emerges with a formidable and balanced portfolio position to deliver multi-year same-store sales oil growth of around 20% per year.

The New Devon is also delivering top line production growth in spite of letting gas volumes decline all while living within operating cash flow. With large high quality acreage positions in each of our core assets, we have no shortage of investment opportunities. Focusing on our go-forward business, we expect E&P capital spending to range from $4.8 billion to $5.2 billion in 2014, excluding about $250 million of capital associated with the divesture assets. This spending focused primarily in low-risk oil development plays is expected to increase average oil production for our go-forward properties to a range of 198,000 to 216,000 barrels per day in 2014. This represents a company-wide oil growth rate of approximately 35% year-over-year on a reported basis for our go-forward assets or about 20% on the same-store sales basis.

The majority of our oil production growth in 2014 will come from aggressive development of Eagle Ford and Permian, driving our reported light oil production in US about 75% higher than 2013 levels. After taking into account declines in natural gas, we expect the mid-point of our total BOE production on our go-forward properties to increase by roughly 10% on a reported basis over 2013. This high margin production mix in 2014 will lead to further margin expansion and translate into improved cash flow growth for the company. As already mentioned, we expect to deliver these attractive results while keeping total capital spending within operating cash flow for the year.

Looking beyond the attractive growth that the repositioned Devon is going to deliver in 2014, our go-forward portfolio is also positioned for excellent high margin growth in 2015. Assuming today’s price environment and constant costs, our organic oil production growth in 2015 is shaping up to exceed 20% while delivering free cash flow. The Eagle Ford and Permian will once again drive competitive production growth in the US and we should see significant oil growth out of Canada as our Jackfish 3 project begins to contribute meaningful volume in 2015. This increase in Canadian oil volumes coincide with our expectation for improved demand and take away capacity.

Increased refinery demand and critical new pipeline and rail take away capacity will allow Canadian crudes unprecedented access to the US Gulf Coast. This will likely narrow the volatile price differentials we’ve seen on Canadian crudes over the past few years, providing a catalyst that should further enhance our profitability in 2015 and beyond.

So in summary, we’re very pleased with the way Devon is positioned for the future. As we integrate the recent acquisitions into our portfolio, maximize divesture proceeds and deliver on growth expectations, we are poised to create value for our shareholders in the upcoming years. So at this point, I’ll turn the call over to David Hager for a more detailed operations review. David?

David Hager

Thanks John, good morning, everyone. I’ll start my comments this morning with a brief review of reserves. Crude reserves for oil, gas and NGLs totalled three billion barrels of oil equivalent at year end. On the Euro side of the portfolio, reserves increased to a record 837 million barrels.

During the year, our oil-focused drilling programs added 112 million barrels of drill-bit oil reserve additions and by drill-bit, I’m referring to extensions, discoveries and performance revisions. These drill-bit oil additions replaced approximately 180% of the oil we produced in 2013.

This was largely driven by our continued success in the Permian and is particularly impressive given that 2013 was not a year of significant heavy oil bookings in Canada. On the gas and natural gas liquid side of the portfolio, not surprisingly 2013 was not a big year for reserve additions given our level of drilling activity.

While we did see positive reserve revisions for higher natural gas prices, this was largely offset by negative revisions mostly attributable to the SEC five-year rule. Given our outlook for gas and NGL pricing relative to oil in the near-to-medium term, these negative revision represent a reduction in the lowest margin barrels within our portfolio and are of little consequence from a value perspective.

In contrast, extensions, discoveries related to our oil-focused development activity generated $4 billion in future net cash flows year-over-year, more than offsetting the negative gas revisions and driving our overall PV-10 up year-over-year. All-in our F&D for the year came in at $22 per Boe. Excluding the negative revisions related to the five-year rule, our all-in F&D would've been approximately $18 per Boe.

Another metric commonly tracked by analyst is proved developed F&D. This metric measures an E&P company’s ability to convert undrilled locations to proved developed reserves in a cost-effective manner ultimately translating into earnings and cash flow.

In 2013, we did an outstanding job of this as we focus on converting the highest margin resources in the cash flow. During the year, we added 392 million Boe of proved developed reserve additions and by this I’m referring to our year-over-year change in proved developed reserves plus production.

These proved developed reserve additions replaced 155% of our 2013 production and were achieved with development capital of approximately $5 billion, translating into a very competitive proved developed F&D cost of just under $13 per Boe.

Before I move into a detailed review of our operations, it is important to understand how we're approaching capital allocation in 2014. With the addition of the Eagle Ford assets and our decision to limit capital spending to our expected cash flow, we have high-graded activity across our portfolio.

This optimization has resulted in a prioritization of our Eagle Ford and Permian and reduced activity levels across several other areas compared to previous years. In 2014, we planned to spend approximately $1.5 billion in the Permian and $1.1 billion in the Eagle Ford, $1.1 billion on our heavy oil projects in Canada as Thermal and Lloyd, $600 million in the liquid rich areas of the Barnett -- of the Barnett shale and Anadarko basin combined and $600 million in our emerging Rockies and Mississippian-Woodford oil plays. With this context in mind, let’s look at new Devon’s key assets in more detail.

Beginning with our core oil areas, fourth quarter production in the Permian averaged a record 86,000 barrels of oil equivalent per day in the fourth quarter, a 29% increase compared to the fourth quarter of 2012.

Light oil production continues to account for roughly 60% of our total Permian production. In the Delaware basin, our Bone Spring horizontal program continues to be one of the most significant drivers of our Permian oil growth.

In the fourth quarter, we brought 21 Bone Spring wells on line with average 30 day IP rates of 800 barrels of oil equivalent per day, of which 70% was light oil. These production results were about 40% over better than our published tight oil profile. We continue to have considerable success in regenerating our inventory in the Bone Springs.

Our record recent drilling activity to third Bone Spring across portions of South East AD and South East New Counties as they were adapt to add roughly 200 additional risk location to our inventory. This marks third increase over the past 12 years to our Bone Spring's inventory. We now have roughly 1600 unreal Bone Spring locations identified and we fully expect at our on-going drilling and geological workable region further inventory increases in the past year right oil play.

We currently have 11 operated rigs running in the Bone Spring. Also in the Delaware Basin, we completed our first horizontal Wolfcamp test in Ward County. During the fourth quarter the Martinsville 124H was brought online with an average 30 day IP rate of 950 barrels of oil equivalent per day including 800 barrels of oil. This is an encouraging result that has positive implications for our more than 100,000 net perspective acres in Delaware Wolfcamp.

So, in total across the Delaware Basin we planned to invest approximately 900 million of capital and drill approximately 160 wells in 2014. Our Bone Spring program will once again be the primary focus of our activity in the area where it was planned to stand about $600 million of capital and drill roughly 130 wells. With continued success in the Bone Spring and additional gas take away capacity anticipated over the next 12 months. We expect to have the option to increase our pace of development in the Bone Spring in 2015.

Although our 2014 program in Delaware Basin will be almost exclusively focused on our low risk high return Bone Spring oil development. We do plan to continue appraising our Delaware Basin Wolfcamp acreage this year. Shifting to the Midland-Basin we continue to see solid results from our oil development program and the Wolfcamp Shale where we have a joint venture partnership with Sumitomo. During the fourth quarter, we tied in 24 new horizontal Wolfcamp wells with a niche of 30 day production rates averaging 410 barrels of oil equivalent per day, right in line with our type well expectations.

On the drilling front we set a record in the fourth quarter, taking just four days to drill a well at TD. Well not the average, it does illustrate the success we are having and achieving greater efficiencies and lowering costs. We are currently drilling or currently running five operated rigs and expect to add a six rig in April.

In 2014, the partnership will spend approximately $800 million and drill of about 140 wells after the benefit for our drilling [indiscernible] Devon's portion will be just over $200 million in the play this year. In summary for the Permian, we expect $1.5 billion capital program to drive strong oil production growth for the company in 2014. Our $1.3 million net acres in the Permian represent one of the largest and highest quality acres positions in the industry.

We have established thousands of undrilled, low risk locations in the Permian and with our success scenarios like Bone Spring, this inventory continues to grow. In addition, the success of our on-going efforts to improve efficiencies and reduce cost is further enhancing the returns in our light oil development plays. As we announced in November, Devon has acquiring 82,000 net acres in the world class Eagle Ford oil play.

This acreage is located in DeWitt and Lavaca counties, which was proven to be in the very best part of Eagle Ford, capable of delivering outstanding well results that ultimately translate into exceptional rates of return, with the majority of our acreage de risks, adding this top tier light oil development opportunity to our portfolio provides additional low risk repeatable oil growth for years to come.

Causing this transaction remains on track for the beginning of March, for those of you modelling Devon we expect our net product in Eagle Ford to average between 70,000 and 80,000 BOE per day for the ten months that we will have assets in 2014. Also, assuming our March closing we expect our capital investment in Eagle Ford to be about $1.1 billion in 2014. These forward looking estimates for product and capital are right in line with our previously provided 2014 guidance after you adjust for not only Eagle assets in January or February.

At our thermal oil projects in Northeast Alberta, fourth quarter gross production from our two Jackfish projects averaged roughly 58,000 barrels of oil per day or 53,000 barrels per day after royalties. As a reminder, our reported net thermal oil production can fluctuate due to the slidings royalty scale imposed by the Alberta government on these projects.

The factors that impact the sliding scale include cost recovery, commodity pricing and the foreign exchange rate. At Jackfish 1, gross production averaged 35,000 barrels per day or 31,000 barrels per day net of royalties. At Jackfish 2, fourth quarter gross production continued to ramp up, averaging all-time high of 23,000 barrels of oil per day or 21,800 barrels per day net of royalties.

Production from our new well pad that began steaming in the third quarter, have been ramping up as expected. This pad had peak gross production, is expected to contribute up to 8,000 barrels of oil per day. It is worth noting in spite of record low temperatures this winter, our Jackfish 1 and Jackfish 2 facilities have maintain 99% uptime, continuing their recurring of excellent reliability and efficiency.

Construction of Jackfish 3 is nearly complete with total capital expenditures for the plant and an initial well pad projected to come in on budgets at a $1.4 billion. Plant commissioning activities will begin in the second quarter, and we expect to begin injecting steam in the third quarter this year.

Delivery of first oil is scheduled to occur late this year with production ramping up throughout 2013. As John mentioned, we are excited about resumption of oil growth out of our Canada assets as our Jackfish 3 project continues to contribute meaningful volumes in 2015.

It appears that the timing of our oil growth and Canadian oil volumes will coincide nicely with the improved demand and takeaway capacity expected in the market. We’ve continued ramp up of heavy throughput at BP’s Whiting refinery, the addition of new rail facilities that could add up more than 500,000 barrels a day of capacity and the new 600,000 barrels per day Flanagan South pipeline in U.S. Gulf Coast are all expected later this year.

These factors should have a narrowing impact on differentials and reduce the overall pricing volatility we have seen on Canadian crudes over the past few years. Ultimately, we expect these factors to further enhance our profitability in 2015 and beyond.

At Pike, our thermal oil sands joint venture with BP, we expect to make a decision on the first phase of Pike development and 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 our two core liquids rich areas, the Barnett and Anadarko Basin, with decreased growth capital allocated to these areas, our focus remains managing based production. Between the Barnett and Anadarko Basin, we plan to invest about $600 million and plan to drill approximately 200 wells in only the most economic portion of these plays.

In aggregate, we expect these properties to generate about $1 billion of free cash flow in 2014. These areas also represent significant gas optionality for our portfolio, should the economic environment improve for gas. And finally, on the emerging play front, we continue to evaluate potential across our Mississippian-Woodford Trend position in North Central Oklahoma.

December production for their play averaged 16,000 Boe per day, representing a 47% increase from the September average and exceeding our target exit rate of 15,000 Boe per day. For the fourth quarter, total production averaged 14,000 Boe per day. This solid production was driven by 66 wells tied in on our joint venture acreage with average 30-day IP rates of about 300 Boe per day, right in line with our tight curve expectations.

As I mentioned earlier, the anticipated addition of the Eagle Ford assets to our opportunity set and our decision to grow within operating cash flow has resulted in high grading across our portfolio and the Mississippian-Woodford is no exception. In 2014, we expect to maintain positive momentum in this play focusing our activity on our joint venture acreage where we have the benefit of the JV carry. The partnership will spend approximately $850 million to run an inter-rig program and drill more than 200 wells. After the benefit of Devon’s drilling carry, Devon’s portion will be about $200 million in the play this year.

So in summary, we had strong execution in 2013 and we’re on course to deliver another year of robust growth in 2014. With that, I’ll turn the call back to John for the financial review and outlook, John?

John Richels

Thanks, David. Our new Chief Financial Officer, Tom Mitchell joined us on Monday of this week and of course, a lot of you know Tom and I’d just like to take this opportunity to welcome Tom to the Devon senior leadership team. For those of you who don’t know Tom, I’m sure you’ll have the opportunity or many opportunities to get to know him over the next while. Since Tom has only been here for a couple of days, I’m going to cover the financial review today. But you can expect to hear from Tom in future quarters.

So let me start with a brief review of the financial and operating results for 2013 as well as a bit of a commentary on our outlook for 2014. For those of you modeling Devon, we will file a Form 8-K after the call today that contains detailed first quarter and full year estimates for both our go forward assets and the divestiture assets. Estimates for our divestiture assets assume a full year of results. As we close on these divestiture packages throughout the year, we’ll provide updated guidance. So let’s start with production. Our top line production in the fourth quarter averaged 696,000 barrels of oil equivalent per day which was well above the midpoint of our previous forecast.

Looking specifically at the oil side of our business, we again delivered excellent volume growth. Fourth quarter oil production averaged 177,000 barrels per day setting a new quarterly record and exceeding the top end of our guidance range by about 2000 barrels per day. Our most significant growth came from the U.S. where high margin, light oil production increased 32% year-over-year. Looking forward to the first quarter and assuming one month of contribution from the Eagle Ford properties, we expect our average daily oil production from our go forward properties to range between 172,000 and 180,000 barrels per day which excludes about 14,000 barrels per day that are associated with the divestiture assets.

This implies a first quarter year-over-year growth rate of around 20% for our go forward properties on a reported basis. Driving this first quarter growth is a 50% increase and high margin oil production from our go forward U.S. operations. Combining this meaningful oil growth with our projected growth in NGLs and the declines we expect in natural gas production, we expect our first quarter production to range between 556,000 and 579,000 BOEs per day for our go forward properties. Now that excludes roughly 130 BOEs per day that’s attributable to the divestiture assets.

This represents a top line growth rate in the mid-to-high single digits for our go forward properties on a reported basis compared to the same period a year ago. We’ll post a historical reconciliation of retained and non-core asset production on our website later today. Moving to price realizations in the fourth quarter, our regional pricing by product was generally in line with expectations. One notable exception was wider than expected differentials on Canadian oil production.

For the fourth quarter Devon’s realized Canadian oil price before hedges averaged 50% of the WTI benchmarks price or about $48.50 per barrel. However, we did mitigate the impact on realizations with the cash settlements on our Western Canadian select basis swats. The basis swats enhance their overall oil price in Canada or the quarter by more than $4 per barrel or nearly 10%.

As many of you know by now, the fourth quarter weakness in Canadian oil pricing resulted from high levels of refinery downtime and restricted oil rates on key export pipelines. The good news is that these temporary bottlenecks have gradually improved, narrowing differentials in the first quarter. As a result, we now expect our Canadian oil price realizations in the first quarter to be approximately 60% of WTI.

Turning now to our midstream business, our marketing and midstream operating profit reached $513 million in 2013. This result came in at the top half of our guidance range and represents a 25% increase compared to 2012. The increase in operating profit was attributable to improved natural gas prices during the year and also strong cost control.

Moving to 2014, we expect our first quarter midstream operating profit to range between $125 million and $155 million. This forecast assumes the transfer of most of our midstream business to EnLink Midstream during March, which will have only a minor impact on first quarter reporting.

After accounting for the inclusion of EnLink, our full year 2014 midstream operating profit is expected to range from $685 million to $755 million, which is a 40% increase compared to 2013. Beyond the first quarter, the EnLink transaction will have more significant implications on our go-forward financial reporting.

Because we are the majority owner of EnLink’s general partnership at 70% and the MLP at 53%, accounting guidelines require that 100% of EnLink’s revenues, expenses, debt and capital be consolidated within our financial statements. The minority ownership interest from the financial line items that we do not own will be netted together and deducted on a line item in our financials entitled, non-controlling interest. We expect our non-controlling interest cutback for the full year 2014 be less than $50 million.

It’s worth nothing that the economic reality of the EnLink transaction is very different from the accounting presentation. Devon, in fact, does not own EnLink’s assets or revenues, we’re not obligated for EnLink’s expenses or indebtedness and EnLink’s capital expenditures do not come from our cash balances.

The economic reality is that we own a large portion of the entities that make up EnLink and receive a large chunk of EnLink’s cash distributions. Assuming that we had closed the transaction on January 1st of this year, our share of distributions would have been expected to be approximately $270 million for 2014. And as EnLink executes its growth plans and increase its payout, our distributions are expected to grow.

Moving now to expenses, we did a good job controlling cost across our portfolio throughout 2013. In the fourth quarter, our total pre-tax cash cost came in at $15.05 per Boe, that’s about a 1% decline compared to the year ago quarter. Overall, our cost structure remains one of the best in the industry, even as we transition our portfolio to higher margin, but higher cost oil production.

Looking at cost trends in 2014, the 100% consolidation of EnLink Midstream will place upward pressure on a few expense line items, but the net effect of EnLink is positive to our earnings and cash flow.

As I mentioned earlier, 8-K filings that will be available after the call today contains detailed first quarter and full year estimates.

Now before we open the call to Q&A, I would like to conclude my remarks with a quick review of our financial condition.

In the fourth quarter, our operating cash flow totaled $1.4 billion, a 26% increase compared to the year ago period. When you include the $419 million of cash payments received from asset sales during the year, Devon generated total cash inflows of $5.9 billion in 2013.

From a balance sheet and liquidity perspective, we remain exceptionally strong with investment grade credit rating and cash balances totaling $6.1 billion. In December, we repatriated another $2.3 billion of foreign cash back to the U.S. You may recall we repatriated about $2 billion of foreign cash balances earlier in 2013, so in total we’re able to successfully repatriate $4.3 billion of foreign cash back to the US in 2013 at an estimated tax rate of only 4%. To provide some perspective on the significance of this you might recall after divesting our international assets in 2010 and 2011, we guided towards a tax rate of about 20%. The lower tax rate on the amount repatriate to the US resulted in an incremental $700 million benefit to Devon shareholders are nearly $2.00 per share. In the fourth quarter, we also issued $2.2 billion -- $2.25 billion of senior notes through a combination of two, three and five-year offerings and entered into an undrawn $2 billion senior term loan facility.

Proceeds from the senior notes, the term loan facility and cash on hand will fund our previously announced Eagle Ford acquisition. As a result of these debt offerings at December 31st our net debt was $6 billion. Our year end capital structure pro forma for the closing of the Eagle Ford, EnLink and Canadian Conventional transactions increases our net debt balances to just over $10 billion of which roughly $1 billion is attributable to the EnLink consolidation. So even before any proceeds from our US divesture process that would further reduce debt, Devon is very well positioned financially with solid investment credit rating. So with that I’ll turn the call back over to Vince for the Q&A, Vince.

Vince White

Operator, we’re ready for the first question.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Evan Calio from Morgan Stanley, your line is now open.

Operator

Your next question comes from the line of Brian Singer from Goldman Sachs, your line is now open.

Brian Singer - Goldman Sachs

Can you put your E&P budget in context versus 2013, $250 million moves out for the Canadian sale then we had $1.1 billion for the Eagle Ford, can you talk more specifically about where are you’re seeing the high grading what the total change in carry is and whether capitalized interest is included in your $4.8 billion to $5.2 billion?

David Hager

Hi Brian, this is David Hager, I’ll take a stab at that. First off, capitalized interest and G&A is not included in the $4.8 billion to $5.2 billion. When you look at where we’ve high graded the program I’ll say roughly the Permian activity is about the same; we’ve obviously added $1.1 billion in Eagle Ford, the overall capital is slightly lower than we had last year, probably a couple of hundred million or so, so there is a little bit of reduction. The biggest reduction will be in our Barnett and Cana areas where we are drilling less of the liquids rich opportunities and we’re also spending less money in the Canadian Conventional as well, and then finally we have a little bit smaller land budget this year as compared to last year. So if you look in our key development area of the Permian it’s essentially flat, key oil development area essentially flat, the heavy oil essentially flat, the addition of a oil or condensate area in the Eagle Ford and cutting back in liquids rich drilling land and the Canadian Conventional.

John Richels

Brian, just to close the loop on that let you know that capitalized G&A and interest are about $400 million and that those are included in the total capital when we say we intend to live within cash flow in 2014.

Brian Singer - Goldman Sachs

Great, thanks, is there a major change in the carry, you didn’t mention what your after carry numbers would be in a couple of the areas but do you expect a major cause in the carried interest?

David Hager

No, it's essentially flat.

Brian Singer - Goldman Sachs

Okay, thanks. And then in the Permian, can you talk more specifically regarding the Bone Spring wells that are trending well above your type curve whether this is something that’s regionally concentrated or specifically area concentrated or whether that broader takeaway is across your Delaware position?

John Richels

Well, I would say, we're hopeful and optimistic that it is broader takeaways across the entire Bone Spring’s position. What we've done, Brian is we have moved our activity from the North Western portion of our acreage position in Lea and Eddy counties expanding that to the South and Southeast in the same counties so to where we have additional acreage.

We are starting to appraise those areas and what we're finding is that we're getting as good a well result if not better in the South and Southeast area as we had in the Northwest portion of our acreage position. Now we don't have as many wells there yet but so far the results are very encouraging.

So that's why we're optimistic this inventory is going to continue to grow and frankly, we haven't booked hardly any PUDs, just being a little bit conservative there, we haven't booked hardly any PUDs on the basis of all the results that we've had there as well. So we're very optimistic that the results are going to continue and that we are actually going to be able to continue to grow the inventory as well.

Brian Singer - Goldman Sachs

Great. Thank you.

John Richels

Operator, we're ready for the next question.

Operator

Your next question comes from Evan Calio from Morgan Stanley. Your line is now open.

Evan Calio - Morgan Stanley

Hey. Good morning guys. Can you hear me now?

John Richels

Yes. Thank you.

Evan Calio - Morgan Stanley

Oh! Good. So first question maybe a follow-up on the Permian, that largely flat CapEx guide there but could you provide a rig and well count assumptions there? And then also a very strong horizontal Delaware Wolfcamp well in Ward county, just any other additional color around the well and costs, lateral length, and whether you’re targeting any other shallower zones here in 2014 or just going after the deeper formation? Thanks.

David Hager

Yeah. And we're going to, again, as I said, our activity level is essentially flat this year at around $1.5 billion, total; we're going to be drilling somewhere around the order of 350 wells across the entire Permian position all while utilizing 22 to 23 rigs, they will vary a little bit during the year, somewhere on that order.

As I said during the call about $900 million of that is going to be spent in the Delaware Basin, primarily drilling Bone Spring wells, about 130 Bone Spring wells, about 160 overall wells, we’ll have 11 to 12 rigs working on that play this year.

I also mentioned the Midland-Wolfcamp where we are going to spent about $200 million, in that area we plan to drill about 150 wells -- 140 wells or so in the Midland-Wolfcamp Shale and maybe about 10 or so in the Cline.

We'll also spend about $200 million in the Wolfberry drilling about 40 wells using a couple of rigs there; in the Central Basin platform we’ll have about 10 wells using a couple of rigs and then we'll spend about $150 million additionally for leasing facilities, OBO, and other type projects. So there is a, I think a pretty comprehensive breakdown of our $1.5 billion.

Evan Calio - Morgan Stanley

That's great. And any other in terms of the…

John Richels

I'm sorry, on the Delaware…

Evan Calio - Morgan Stanley

Yeah.

John Richels

On the Delaware Wolfcamp, we're very excited about it and so we think there is potential, we have a significant acreage position not only on the Texas side, but as you move up into New Mexico, we have some geological modeling and thoughts, I would say, about where we think the most prospective area is. I obviously don't want to get into lot of details around that, but we're encouraged by what we see, we're going to continue to drill a handful of wells this year to evaluate portions of our acreage position and see if we can get some additional opportunity to capture.

Evan Calio - Morgan Stanley

Great. Just secondly if I could on the CapEx. I don't know if you gave a midstream component, if that was within the guidance that was flat year-on-year, and I mean, how do you think about midstream capital spend when living within the cash flow, meaning should that be included now that there is a strong inventory of assets that can be tax efficiently monetized into EnLink post deal close?

John Richels

Yeah. When you look pre-consolidation numbers for Devon, so excluding EnLink any capital expenditures that we will undertake are included in our segment that we intend to live within cash flow. And obviously a lot of the capital expenditures on a consolidated basis will really be EnLink’s capital.

Evan Calio - Morgan Stanley

Right. But that ultimately could be monetized through the MLP as you think about it going forward. Is that fair?

John Richels

That is fair. And we’re spending about $400 million on completion of the expansion on the Access Pipeline and that’s clearly a potential dropdown item.

Operator

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

Arun Jayaram - Credit Suisse

Good morning

John Richels

Good morning, Arun.

Arun Jayaram - Credit Suisse

I have a quick question, just kind of clarifying the oil guidance for 2014. Is it 198 to 216 MBOE per day – BOEs per day, pardon me, just on oil excluding Canada?

John Richels

No, that’s oil including Canada, Arun.

Arun Jayaram - Credit Suisse

Including or excluding Canada, just wanted to clarify that.

John Richels

That’s including Canada, but not – exclusive of the barrels we’re selling.

Arun Jayaram - Credit Suisse

That’s what I wanted to clarify.

John Richels

Yeah, there’s some oil in that – there some minor oil properties in the Canadian asset package and that number that we gave you excludes those barrels, excludes that 15,000 – excludes about 15,000 barrels that we’re selling.

Vincent White

So that is the go forward company.

Arun Jayaram - Credit Suisse

Thanks for clarifying that. And then John, you mentioned 20% growth on top of that for 15 would be your expectation as we stand here today?

John Richels

Yes.

Arun Jayaram - Credit Suisse

Okay, just wanted to clarify that.

John Richels

Yeah, thank you.

Arun Jayaram - Credit Suisse

The second point I just wanted to comment John, you talked about obviously a lower CapEx number for ’14 and you expect to see kind of 20% oil growth going forward. Do you expect to be able to do that within cash flows on a go forward basis?

John Richels

Yeah, absolutely. The position we’ve put ourselves into Arun, is with these steps that we’ve taken over the past while, is we’ve got a company now that we can grow or we can grow oil on a multiyear basis at about 20% even after we’ve let gas decline because we’re not investing in gas properties or dry gas properties at this time. We’ll still see top line growth in the mid single digits on a six to one basis probably around close to 10% on the 20 to one basis if you want to look at it more in an economic equivalency basis. And we can do all of that while living within cash flows. So it really reflects the big step up in margin that we’ve been able to accomplish and the much more prospective and efficient asset base that we have today going forward.

Arun Jayaram - Credit Suisse

That’s helpful. And my last question is I don’t know if Darryl Smette is on the line. I know [inaudible] is expected to come on line about the middle part of the year, just wanted to – Darryl could maybe comment on expectations on heavy oil differentials going forward after find [indiscernible] online.

Darryl Smette

Certainly, I’ll be happy to. You know, Dave mentioned in his comments and John also mentioned in his comments, over the last two and a half or three years we’ve had supply in demand get fairly low balanced for oil coming out of Canada. When I use the term demand, I’m talking about refining capacity, the oil capacity, pipeline capacity. We are starting to see now a speculation between that supply in demand as new refineries come online or have [indiscernible] and that is more heavy oil to that. And we’re also seeing increase in pipeline exploits coming out of Canada to the United States. One of those as you mentioned is planned in south.

We’re planning it just outside of Chicago, for those of you who don’t know, it’s a pipeline that will move about 600,000 barrels a day from Chicago down to Kuching where it will interconnect with a couple of other pipelines and take oil to the Gulf Coast. The reason that is very important for us is about 9 million barrels of refining capacity exists in the Gulf Coast, about 35% of that is for heavy oil.

So it provides excellent opportunity to move more heavy oil to the Gulf Coast market and that’s why we think as we go through the last part of this year, we actually could find South is going to be on the end of the third quarter, later fourth quarter. But we will start to see differentials become less volatile that they have been and that those differentials will continue to get narrow.

Vincent White

This is Vince. I want to correct something I said earlier. I said that we were going to spend about $400 million in 2014 on the expansion of the Access Pipeline. That’s actually our total Devon portion of midstream expenditures. And about three fourths of that is the Access Pipeline.

Arun Jayaram - Credit Suisse

Thanks a lot, gentlemen.

Operator

Your next question comes from the line of Hsulin Peng from Robert Baird. Your line is now open.

Hsulin Peng - Robert W. Baird

Good morning, everyone. So the first question is also a clarification question. I’m sorry if I missed it, but could you give out the production associated with the U.S. non core asset sale that you are expecting this year in your guidance number?

John Richels

It will be in our detail guidance and we did provide the production associated with the Canadian reserves and it previously provided -- okay.

David Hager

I’ve got it here, so the production, maybe fourth quarter 2013 production. First on the Canadian conventional, that we just divested, it was a total of 88,000 Boe per day consisting of 412 million cubic feet of gas a day, 9000 barrels of NGL a day and 10,000 barrels of oil a day. The remaining assets that we’re looking at divesting in the U.S. and again this could vary a little bit depending on what we actually sell. But our anticipated assets sales would have production of around 57,000 Boe per day of which a little over 250 million or so will be gas, about 9000 barrels of NGL a day and 4000 barrels of oil a day.

Hsulin Peng - Robert W. Baird

Okay. Got it.

David Hager

Did I gave what you wanted?

Hsulin Peng - Robert W. Baird

Yeah, that number is excluded from your going forward, that’s a going forward number.

John Richels

That’s not in the new Devon or in the retained assets. And when we talk about new Devon or retained assets, that does not include that number.

Hsulin Peng - Robert W. Baird

Okay. Got it. And if you [inaudible] basis and also potential basis, maybe the tax basis or the assets in the U.S., this will trend out in this tax implication there potentially?

John Richels

In the U.S., our tax basis is fairly low. As you can see that was in the case in Canada. We had a very high basis and we’re able to take advantage of several other opportunities to keep our taxes down. They’re very low number coming on Canada. Now, even though we have a low basis in the United States, these properties would be available for 1031 like kind exchange, that’s something that made a sense of the time.

Hsulin Peng - Robert W. Baird

Okay, yeah, now that will be good. And then my further questions, the first one is regarding the Jackfish 3. So I think you mentioned that the first oil is expected in late ‘14. So is it fair to assume, I guess, I’m just trying to understand the ramp to the 35,000 in 2015. How is that ramp shape, is it graduals that function, how should we think about it?

John Richels

The way that these heavy oil projects work, we are going to start steaming later on this year within the third quarter. And it takes about a period of something like 16 months, 14 to 16 month to ramp up, to get enough heat in the ground, enough steam in the ground to really get that working. So that’s a typical ramp up and so when we talk about that ramp up in oil production, anticipate starting to steam this fall, you start to see an increase, the slight increase in oil production, then it continues to ramp up all the way through ‘15 and then from ‘15 onward, its pretty much running flat at 35,000 barrels a day.

Hsulin Peng - Robert W. Baird

Okay, so it is…

John Richels

Think of it as a steady ramp-up, not a step function.

Hsulin Peng - Robert W. Baird

Okay. But the full -- the peak production is not expected until ‘16.

John Richels

Probably late ‘15 or early ‘16 somewhere near.

Hsulin Peng - Robert W. Baird

Okay, got it. And then in this Woodford area, I thought the production growth was pretty good quarter-over-quarter, this quarter. And you also mentioned that you exceeded your exit rate. I was wondering if you have a new exit rate for 2014…

John Richels

We didn’t catch that area of that. It’s at the Miss-Woodford, you’re talking actually.

Hsulin Peng - Robert W. Baird

Right. Miss-Woodford area.

John Richels

Yeah, we had an exit rate around 16,000 in December, average about 14,000 for the quarter and exceeded our expectations of 15,000. We don't have an absolute exit rate for 2014, we are optimistic as some more 20,000 to 25,000 barrels a day. We’re still doing a lot of appraisal work out there and so there’s going to be variability. So the results probably somewhere on that order of magnitude.

Hsulin Peng - Robert W. Baird

Okay.

John Richels

Okay. We got a lot of questions. So we’re going to move on to the last caller.

Hsulin Peng - Robert W. Baird

Sorry.

John Richels

No problem, thank you.

Hsulin Peng - Robert W. Baird

Okay, thanks.

John Richels

Operator, we're ready for the final, final question.

Operator

Your final question comes from the line of Charles Meade from Johnson Rice. Your line is now open.

Charles Meade - Johnson Rice

Yes. Thanks for getting me in here guys. One quick question, I'm sorry to believe it this point, but John you said that the topline was going to be -- I believe you said top line is going to be 10% for a week in 2014 and let you know update, that is over the year as you saw some of those US assets, is that right?

John Richels

Well, I think what we said is on a going forward basis, multi-year basis, we drill the oil at somewhere around 20% and topline on a 21 basis somewhere around 10%.

Charles Meade - Johnson Rice

Got it. Okay. And then switching to your Eagle Ford. Can you talk a bit about, I know you haven't closed on the acquisition yet, but have you been able to engage with your partner there at all and do you have any thoughts about how you might try to perhaps change, how operations have been running there last year?

David Hager

Yeah, this is Dave. Yeah, we've been able to engage with BHP quite a bit and of course we haven't closed on the transaction yet, but we have had numerous meetings with them, talking about how everything is going and how we might be able to help out with the partnership. I think the one thing in particular that we're going to really bring to the table, it is our ability to execute what you might want to call the machine. The ability to manage the large number of rigs and then actually bring those wells on production with -- in a very timely manner, that's something we're very good at. We have 35 plus rigs running in Barnett at one point and we've been very active with this unconventional plays for a long time. It's of course skillset and I think that's something that we're really going to bring to the table.

We're very impressed with the technical work they are doing, I'll tell you that. So, we think we are going to have a good exchange of technical information, they are very open to listening to us, so we think it's going to be great partnership.

Charles Meade - Johnson Rice

Thanks for that detail John.

John Richels

Thanks, Charles. Well for [inaudible] I'm showing we're a little past at the top of the hour, but just before signing off let me leave you with a few key take away. First, we've taken some bold steps in a relatively short period of time to high grade our portfolio and improve the growth trajectory of our go forward business with our acquisition of the Eagle Ford, the creation of End link and the divesture of a Canadian conventional business as we talked a lot about today.

We have an emergence with a formidable and balanced portfolio positions to deliver oil production growth around 35% in 2014 led by a 75% increase in U.S oil production. We are going to achieve this attractive growth without spending within operating cash flow and lastly, while the remaining exciting changes occurring at Devon, our approach to business remains the same. We will continue to pursue our top strategic objective and that is to maximize long-term growth in cash flow per share after adjusting for debt. So, we look forward to talking with you again on the next call. And thank you very much for joining us today.

Operator

This concludes today's conference you may now disconnect.

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Source: Devon Energy's CEO Discusses Q4 2013 Results - Earnings Call Transcript
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