德文能源 (DVN) 2013 Q4 法說會逐字稿

Welcome to Devon Energy's fourth-quarter and year-end 2013 earnings conference call.

(Operator Instructions)

This call is being recorded. At this time, I would like to turn the conference over to Mr. Vince White, Senior Vice President of Communications and Investor Relations. Sir, you may begin.

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 up 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 you have any additional questions.

On the call today, we are 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 to 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 US Securities law. These are, of course, subject to a number of assumptions, risks, 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 will reference certain non-GAAP performance measures. When we use these measures, we are 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.

Well, 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 operating cash flow.

Additionally, we have taken some bold steps in a relatively short period of time to high grade our portfolio and improvement Devon's growth trajectory. We did this through an accretive Eagle Ford shale acquisition and 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 US oil production, our highest margin product. Driven by our development programs in the Permian basin, we increased our light sweet crude production in the US to 78,000 barrels per day, up 32% compared to 2012.

This highly profitable US oil-production growth is particularly impressive, considering the large base of oil production that we're growing off, a base that ranks Devon as one of the largest independent oil producers in the US. 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 a 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 US 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 US 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 develops its assets.

Another 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 US 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 CAD3.125 billion, or, at current exchange rates, $2.8 billion. This transaction values our natural gas-levered Canadian conventional business at approximately 7 times 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 US, we expect net proceeds of approximately $2.7 billion. We will utilize these net proceeds to reduce the debt that we're 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 CAD155 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 US, 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 a 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 positioned 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 divestiture 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 a same-store sales basis. The majority of our oil-production growth in 2014 will come from aggressive development of the Eagle Ford and Permian, driving our reported light-oil production in the US about 75% higher than 2013 levels.

After taking into account declines in natural gas, we expect the midpoint 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 I 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 volumes in 2015. This increase in Canadian oil volumes coincides with our expectation for improved demand in takeaway capacity.

Increased refinery demand and critical new pipeline and rail takeaway 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 are very pleased with the way Devon is positioned for the future. As we integrate the recent acquisitions into our portfolio, maximize divestiture 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 Dave Hager for a more detailed operations review. Dave?

Thanks, John. Good morning, everyone. I'll start my comments this morning with a brief review of reserves. Proved reserves for oil, gas, and NGLs totaled 3 billion barrels of oil equivalent at year end. On the oil 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 am 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 liquids side of the portfolio, not surprisingly, 2013 was not a big year for reserve additions, given our reduced 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 revisions represent a reduction in the lowest margin barrels within our portfolio and are of little consequence from a value perspective. In contrast, extensions and 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 have been approximately $18 per BOE.

Another metric commonly tracked by analysts 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 focused on converting the highest margin resources into cash flow.

During the year, we added 392 million BOE of proved developed reserve additions, and by this, I am 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 are 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 plan to spend approximately $1.5 billion in the Permian; $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 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 Springs horizontal program continues to be one of the most significant drivers of our Permian oil growth.

In the fourth quarter, we brought 21 Bone Springs 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 are about 40% better than our published type well profile.

We continue to have considerable success in regenerating our inventory in the Bone Springs. Our record recent drilling activity in a third Bone Spring across portions of southeast Eddy and southwest Lee counties has allowed us to add roughly 200 additional risk locations to our inventory. This marks the third increase over the past 12 years to our Bone Springs inventory.

We now have roughly 1,600 undrilled Bone Spring locations identified, and we fully expect that our ongoing drilling and geologic work will lead to further inventory increases in this top-tier light-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 120-4H was brought on line 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 prospective acres in the Delaware Wolfcamp.

So, in total, across the Delaware Basin, we plan 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 we plan to spend about $600 million of capital and drill roughly 130 wells.

With continued success in the Bone Spring and additional gas takeaway 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 the 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 in 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 initial 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 to TD. While not the average, it does illustrate the success we are having in achieving greater efficiencies and lowering costs.

We are currently drilling -- or currently running five operated rigs and expect to add a sixth rig in April. In 2014, the partnership will spend approximately $800 million and drill about 140 wells. After the benefit of our drilling carry, Devon's portion will be just over $200 million in the play this year.

In summary, for the Permian, we expect our $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 acreage positions in the industry. We have established thousands of undrilled low-risk locations in the Permian, and with our success in areas like the Bone Spring, this inventory continues to grow. In addition, the success of our ongoing efforts to improve efficiencies and reduce costs is further enhancing the returns in our light-oil development plays.

As we announced in November, Devon has acquired 82,000 net acres in the world-class Eagle Ford oil play. This acreage is located in DeWitt and Lavaca counties, which has proven to be in the very best part of the Eagle Ford, capable of delivering outstanding well results that ultimately translate into exceptional rates of return.

With the majority of our acreage de-risked, adding this top-tier light-oil development opportunity to our portfolio provides additional low-risk repeatable oil growth for years to come. Closing this transaction remains on track for the beginning of March. For those of you modeling Devon, we expect our net production in the Eagle Ford to average between 70,000 and 80,000 BOE per day for the 10 months that we will own these assets in 2014.

Also, assuming a March closing, we expect our capital investment in the Eagle Ford to be about $1.1 billion in 2014. These forward-looking estimates for production and capital are right in line with our previously provided 2014 guidance, after you adjust for not owning Eagle Ford 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 sliding 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 fourth -- in the third quarter has been ramping up as expected. This pad, at peak gross production, is expected to contribute up to 8,000 barrels of oil per day. It's worth noting, in spite of record low temperatures this winter, our Jackfish 1 and Jackfish 2 facilities have maintained 99% uptime, continuing their trend of excellent reliability and efficiency.

Construction of Jackfish 3 is nearly complete, with total capital expenditures for the plant and initial well pads projected to come in on budget at $1.4 billion. Plant commissioning activity will begin in the second quarter, and we expect to begin injecting steam in the third quarter of this year. Delivery of first oil is scheduled to occur late this year, with production ramping up throughout 2015.

As John mentioned, we are excited about the 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 in Canadian oil volumes will coincide nicely with the improved demand and takeaway capacity expected in the market.

The continued ramp-up of heavy throughput at BP's Whiting refinery, the addition of new rail facilities that can add up more than 500,000 barrels a day of capacity, and the new 600,000-barrel-per-day Flanagan South pipeline in the US 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 the pipe 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 base 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 portions 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 the potential across our Mississippian-Woodford Trend position in north central Oklahoma. December production for the play averaged 16,000 BOE per day, representing a 47% increase from the September average, and exceeded 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 type curve expectations.

As I mentioned earlier, the anticipated addition of the Eagle Ford assets to our opportunity set and our decision to live 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 $860 million to run an eight-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 are poised 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?

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 am 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 assumes 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 2,000 barrels per day. Our most significant growth came from the US 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 in high-margin oil production from our go-forward US 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 benchmark 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 swaps. The basis swaps enhanced our overall oil price in Canada for 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 flow 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're 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 Noncontrolling Interest. We expect our noncontrolling interest cutback for the full-year 2014 to be less than $50 million.

It's worth noting 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 are 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 1 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 increases its payout, our distributions are expected to grow.

Moving now to expenses, we did a good job controlling costs across our portfolio throughout 2013. In the fourth quarter, our total pretax cash costs 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 at a 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, our 8-K filing 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'd like to conclude my remarks with a quick review of our financial position. 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 US. You may recall, we repatriated about $2 billion of foreign cash balances earlier in 2013. So, in total, we were 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 repatriated to the US resulted in an incremental $700 million benefit to Devon shareholders, or nearly $2 per share.

In the fourth quarter, we also issued $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 31, 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 divestiture process that would further reduce debt, Devon is very well positioned financially, with solid investment-grade credit rating.

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

Operator, we are ready for the first question.

Absolutely. (Operator Instructions)

Evan Calio, Morgan Stanley.

Let's move on.

Brian Singer, Goldman Sachs.

(Technical difficulty).

Brian, we just heard the tail end of that.

All right. If this is better, and I'll move on here. Can you put your E&P budget in context versus 2013? $250 million moves out for the Canadian sale, then we add $1.1 billion for the Eagle Ford. But can you talk more specifically about where you are seeing the high grading, what the total change in carry is and whether capitalized interest is included in your 4.2 to 5 -- $4.8 billion to $5.2 billion?

Hi, Brian. This is Dave Hager. I will take a stab at that. First off, capitalized interest in 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'd 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 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 are also spending less money in the Canadian conventional as well. And then finally, we have a little bit smaller land budget this year compared to last year.

So, if you look at our key development areas of the Permian, it's essentially flat, [peak] oil development areas essentially flat, the heavy oil essentially flat, the addition of an oil or condensate area in the Eagle Ford and cutting back in liquids rich drilling land and the Canadian conventional.

Brian, I might -- just to close the loop on that, let you know that capitalized G&A and the 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.

Great, thanks. And is there a major change in the carry? You did mention what your after carry numbers would be in a couple of the areas, but do you expect a major change in the carried interest benefits?

No. It's essentially flat.

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 is regionally concentrated or specifically area concentrated or whether there are broader takeaways across your Delaware position?

Well, I would say we are hopeful and optimistic that it is broader takeaways across the entire Bone Springs position. What we've done, Brian, is we've accelerated -- or we have moved our activity from the northwestern portion of our acreage position in Lee and Eddy counties, expanding that to the south and southeast in the same counties 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.

Great. Thank you.

Evan Calio, Morgan Stanley.

Good morning, guys. Can you hear me now?

Yes. Thank you

Good. I don't know what happened there. The first question, a follow-up on the Permian, largely flat CapEx guide there, but can you provide a rig and well count assumptions there?

And then also, 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 formations? Thanks.

Yes. And we are going to -- again as I said, our activity level is essentially flat this year at around $1.5 billion. Total, we are going to be drilling somewhere on the order of 350 wells across the entire Permian position while utilizing 22 to 23 rigs. It'll vary a little bit during the year, but 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 Springs wells, about 130 Bone Springs wells, but 160 overall wells, we will have 11 to 12 rigs working on that play this year.

I also mentioned the Midland Wolfcamp where we are going to spend about $200 million in that area, plan to drill about 150 wells -- 140 or so in the Midland Wolfcamp shale and maybe about 10 or so in the Cline. We will also spend about $200 million in the Wolfberry, drilling about 40 wells using a couple of rigs there.

In the central basin platform, we will have about 10 wells using a couple rigs and then we will spend about $150 million additionally for leasing facilities, OBO and other type projects. So, there's, I think, a pretty comprehensive breakdown of our $1.5 billion.

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

I'm sorry, on Delaware Wolfcamp. We are 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 perspective areas.

I obviously don't want to get into a lot of details around that, but we are encouraged by what we see. We are going to continue to drill a handful of wells this year to evaluate portions of our acreage position and see if we can't get some additional opportunities captured.

Great, and just secondly, if I could, on the CapEx. I don't know if you gave the midstream component, if that was within the guidance that was flat year-on-year. How do you think about midstream capital spend when living within 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.

Yes. When you look pre-consolidation numbers for Devon, so excluding EnLink, any capital expenditures that we'll undertake are included in our statement 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.

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

That is fair. And we are spending about $400 million on completion of the expansion of the Access Pipeline, and that is clearly a potential drop-down item.

Great. Appreciate it, guys. Thanks.

Arun Jayaram, Credit Suisse.

Good morning. I have a quick question just kind of clarifying the oil guidance for 2014. Is it 198,000 to 216,000 MBOE per day -- BOP per day, pardon me, just on oil, excluding Canada?

Yes. That's oil including Canada, Arun.

That's including or excluding Canada? I just want to clarify that.

It's including Canada, but not -- but exclusive of the barrels we're selling.

Selling (inaudible). That's what I wanted to clarify.

Yes. I'm sorry. (multiple speakers)

Excluding asset sales.

Yes. There's some oil in that -- there's some minor oil properties in the Canadian asset package, and that number that we gave you excludes those barrels.

Excludes that.

About 15,000 -- excludes about 15,000 barrels that we're selling.

So, that is the go-forward company.

That's -- thanks for clarifying that. And then John, you mentioned 20% growth on top of that for 2015 would be your expectation as we stand here today?

Yes.

Okay. I just wanted to clarify that.

Yes. Thank you.

The second point I just wanted to comment, John, you talked about obviously a lower CapEx number 2014, and you expect to see 20% oil growth going forward. Do you expect to be able to do that within cash flows on a go forward basis?

Yes, 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 -- where we can grow oil on a multiyear basis at about 20%, even after we 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 6 to 1 basis, probably around close to 10% on a 20 to 1 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 flow. 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.

That's helpful. And my last question is just, I don't know if Darryl Smette is on the line, I know Flanagan South is expected to come online about the middle part of the year. I just wondered if Darryl could maybe comment on expectations on heavy oil differentials going forward after Flanagan South comes online.

Certainly, Arun, I'd be happen to. As Dave mentioned in his comments and John also mentioned in his comments, over the last 2.5 or 3 years, we've had supply and demand be fairly well-balanced for oil coming out of Canada. And when I use the term demand, I'm talking about refining capacity, rail capacity, pipeline capacity.

We are starting to see now a separation between that supply and demand as new refineries come online or we have de-bottlenecked and added more heavy oil to that. And we're also seeing an increase in pipeline exports coming out of Canada and out through the United States.

One of those, as you mentioned, is Flanagan South. And Flanagan is just outside of Chicago, for those of you that don't know. It's a pipeline that will move about 600,000 barrels a day from Chicago down to Cushing 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 exist in the Gulf Coast, about 35% of that is for heavy oil.

So, it provides an excellent opportunity to move more heavy oil to the Gulf Coast market and therefore, we think as we go through the last part of this year, we actually think Flanagan South is going to be on into the third quarter and the fourth quarter. But we will start to see differentials become less volatile than they have been and that those differentials will continue to narrow.

This is Vince, I want to correct something I said earlier. I said that we are 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.

All right. Thanks a lot, gentlemen.

Hsulin Peng, Robert Baird.

Good morning, everyone. So, the first question is also a clarification question. I am sorry if I missed it, but did you give out the production associated with the US noncore assets sale that you are expecting this year in your guidance number?

I've got it. It will be in our detailed guidance, and we did provide the production associated with the Canadian reserves in a previously provided -- okay.

I've got it here. So, the production -- I'll give you 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, 9,000 barrels of NGL a day and 10,000 barrels of oil a day.

The remaining assets that we're looking at divesting in the US, 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 would be gas, about 9,000 barrels of NGL a day and 4,000 barrels of oil a day.

Okay, got it.

Does that give you what you want?

Yes, that does. That number is excluded from your going forward -- Devon going forward number.

That's not in the New Devon or in the retained assets. When we talk about New Devon or retained assets, that does not include that number.

Okay, got it. And in terms of the basis and also potential, can you just give us, maybe the tax basis for the assets in the US? Just trying to understand the tax implication there potentially.

In the US, our tax basis is fairly low. As you can see, that wasn't the case in Canada. We had a very high basis, and we were able to take advantage of several other opportunities to keep our taxes down to a very low number coming out of Canada. Now, even though we have a low basis in the United States, these properties would be available for a 1031 like kind exchange, if that's something that made any sense at the time.

Okay, yes. That would be good. And then my two other questions, the first one is regarding the Jackfish 3.

I think you mentioned that the first oil is expected in late 2014, so is it fair to assume -- I guess I'm trying to understand the ramp to the 35,000 in 2015. How is that ramp shaped? Is it gradual, step function? How should we think about it?

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 months to ramp up, to get enough heat in the ground, enough steam in the ground to really get that working.

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, a slight increase in oil production. Then it continues to ramp up all the way through 2015 and then from 2015 onward, it's pretty much running flat at 35,000 barrels a day.

Okay, so it (multiple speakers).

Think of it as a steady ramp up. Not a step function.

Okay. But the peak production is not expected until 2016?

Probably late 2015 or early 2016, somewhere in there.

Okay, got it. And then it the 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 so then (multiple speakers).

We didn't catch the area, was the Miss you are talking about, Hsulin?

Right, Miss Woodford area.

Yes, we had an exit rate of around 16,000 in December, averaged 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 it's going to be somewhere 20,000 to 25,000 barrels a day. We are still doing a lot of appraisal work out there, so there's going to be variability to the results. But probably somewhere on that order of magnitude.

Okay.

Okay, we've had a lot of questions, Hsulin, we're going to move on to the last caller. No problem. Thank you.

Okay. Thanks.

We are ready for the final question.

Charles Meade, Johnson Rice.

Yes. Thanks for getting me in here. One quick question. I'm sorry to belabor this guidance point, but John, you said that top line was going to be -- I believe you said top line was going to be 10% BOE growth in 2014 and that you were going to update guidance over the year as you sold some of those US assets. Did I get that right?

Well, I think what we said is on a going forward basis, a multiyear basis, we grow the oil at somewhere around 20% and the top line on a 20 to 1 basis somewhere around 10%.

Got it, okay. And then switching to your Eagle Ford, can you talk 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 kind of thoughts about how you might try to perhaps change how operations have been run there in the last year?

Yes, this is Dave. Yes, 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 is our ability to execute what you might want to call the machine. The ability to manage a large number of rigs and then actually bring those wells on production with -- in a very timely manner. That is something we are very good at.

We had 35 plus rigs running in the Barnett at one point, and we've been very active in these unconventional plays for a long time. It's a core skill set, and I think that's something that we're really going to bring to the table. We are very impressed with the technical work they are doing, I'll tell you that. We think we're 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 a great partnership.

Thanks for that detail, Dave.

Thanks, Charles. Well, folks, I'm showing we're a little past the top of the hour, but just before signing off, let me leave you with a few key takeaways.

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 EnLink and the divestiture of a Canadian conventional business as we've talked a lot about today. Devon emerges with a formidable and balanced portfolio positioned to deliver oil production growth of around 35% in 2014, led by a 75% increase in US oil production.

We're going to achieve this attractive growth while spending within operating cash flow. And lastly, while there are many 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 and cash flow per share after adjusting for debt. We look forward to talking with you again at the next call, and thank you very much for joining us today.

This concludes today's conference. You may now disconnect.