Nov 6, 2013
Executives
Vince White – SVP, Communications John Richels – President and CEO David Hager – EVP, Exploration and Production Jeff Agosta – CFO
Analysts
Scott Hanold – RBC Jeffrey Campbell – Tuohy Brothers Investment Matt Portillo – Tudor, Pickering & Co. David Tameron – Wells Fargo Charles Meade – Johnson Rice Arun Jayaram – Credit Suisse Mark Hanson – Morningstar Biju Perincheril – Jefferies & Co.
Operator
Welcome to the Devon Energy’s third quarter earnings conference call. (Operator instructions) 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.
Vince White
Thank you, and welcome everyone to Devon’s third quarter earnings call and webcast. Today’s call will follow our usual format.
I’ll cover a few preliminary items, and then turn it over to our President and CEO, John Richels, he will provide comments on the quarter. And then following John’s remarks, Dave Hager, our Chief Operating Officer, will provide the operations update.
We’ll wrap up the prepared remarks with a financial review by our CFO, Jeff Agosta. After Jeff’s discussion, we will have a Q&A session and we will conclude the call after about an hour but the investor relations team will be available for the rest of the day for any questions that we don’t get to during the call.
During the call today, we’re going to update some of our forward-looking estimates based on our actual results that we’ve seen over the first nine months of the year and outlook for Q4. While we will not be filing a revised Form 8-K we will post estimates reflecting these adjustments that are provided during the call today on the guidance page of our website.
To access that guidance, click on the guidance link, down within the investor relations section of the Devon website. All references today to our plans, forecasts, expectations, and estimates are forward-looking statements under US securities law.
These are subject to a number of assumptions, risks, and uncertainties, many of which are beyond our control. These statements are, of course, not guarantees of future performance.
You can see a discussion of the risk factors relating to these estimates in our Form 10-K. Also on today’s call, we will reference certain non-GAAP performance measures.
When we use these measures, we’re required to provide certain related disclosures and those can 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. The third quarter was another solid one for Devon, both, operationally and financially as we continued to deliver on our strategic plan.
Higher oil production combined with better prices drove significant improvements in our margins, allowing us to comfortably exceed Wall Street expectations for both earnings and cash flow for the quarter. We achieved third quarter US oil production growth of 38% year-over-year, largely driven by success in our Permian Basin development programs.
Over the past two years we have doubled our light oil production in the US to 81,000 barrels per day and by yearend we expect our US light oil production to top 90,000 barrels per day. Most importantly, our success in growing our US light oil production has resulted in higher margins and improved profitability in the current commodity price environment.
Looking beyond the low-risk development projects that are driving today’s growth, we’re also investing in opportunities that will provide the next leg of high margin production growth for Devon. In the US, we’re highly encouraged by the progress we’ve made with our Mississippi and Woodford and our Rockies oil plays, our light oil production in these plays is growing rapidly and it’s currently approaching 20,000 barrels per day.
Dave is going to speak to this later on in the call. We’re also laying the ground work for continued long-term growth with investments in our world-class portfolio of thermal oil projects in Canada.
These projects remain on-track to produce at least 150,000 barrels of oil per day by the end of the decade. And this highly visible oil production growth out of Canada will be significant contributor to our long-term success.
Our company-wide focus on oil production is not only delivering volume growth but it’s also improving our revenues and cash margins. In the third quarter, oil revenue increased 19% compared to last quarter, accounting for nearly 60% of our total upstream revenue.
This growth in oil revenue has helped increase our cash margin per barrel by 16% year-over-year to its highest level in recent history. Another contributing factor to our margin expansion has been our ability to effectively control costs.
In the third quarter, our upstream cash cost per unit of production remained flat from last quarter. This is noteworthy considering our rapid growth in oil production.
At the same time, our focus on capital discipline has resulted in total capital expenditures for 2013 remaining on-track with the full-year guidance we provided at the beginning of the year. And in the third quarter, cash inflows exceeded our capital demands.
On the liquidity front, we exited September with $4.3 billion of cash with the majority of these funds residing in foreign subsidiaries. Our tax position now affords us the opportunity to repatriate an addition $2 billion of cash to the US around year-end at a tax rate in the mid-single-digits; Jeff will speak to this in a little more detail later on in the call.
Finally, before I hand the call off to Dave, I’d like to briefly review our recent announcement to combine substantially all of our US midstream assets with Crosstex to form a new midstream business. This strategic combination creates one of the largest midstream companies in the United States with assets located in some of the country’s premier oil and gas regions.
Devon will retain significant influence on the direction of the new company through our majority ownership interest in both the general partner and the MLP and majority representation on both boards. This transaction allows us to obtain a marked-based valuation for our US midstream business in a tax deferred manner that’s immediately accredited to our shareholders.
As you may recall, our contribution of midstream assets and resulting equity ownership in the new company was initially valued at $4.8 billion. Based on yesterday’s closing prices, the market value of our ownership interest totals $6.6 billion or 16-times EBITDA of the contributed assets.
This valuation equates to roughly 25% of Devon’s current market capitalization. Just as important, the transaction improved the growth trajectory of our midstream investment.
A key component of our improved growth trajectory is Devon’s 70% ownership in the new general partner. The new general partner will have incentive distribution rights in the MLP in the highest tier, allowing us to disproportionately increase our share of the MLP’s distributable cash flow going forward.
Additionally, the new company’s investment grade credit profile will enable us to secure and execute sizable organic development and acquisition opportunities across the midstream value chain. This positions the new business to deliver attractive long-term growth in distributions.
Another significant advantage of this transaction is our improved capital efficiency. Upon closing of the transaction, future capital requirements associated with our contributed midstream assets will reside with the new company.
This will lessen our overall capital intensity and preserve cash flow for our growing E&P upstream business. Furthermore any buildout of new midstream assets supporting our E&P business could be completed by the new company.
This approach eliminates the capital call on Devon while allowing us to maintain influence over the development and management of the assets via our majority ownership of the new company. Our relationship with the new company also provides us the opportunity to attractively sell additional midstream assets currently held or developed by Devon in a manner that's accretive to our shareholders.
So overall the transaction in the resulting new company greatly accelerates the value proposition of Devon’s previously announced standalone MLP and is another clear and successful example of our efforts to unlock value for our shareholders. So in summary, we continue to successfully execute our business plan, both operationally and financially.
This is evidenced by the continuation of strong oil production growth from our development projects and the progress we’re making on emerging plays that will enhance our long-term oil and liquids growth profile. Furthermore our pursuit of high-margin production, combined with effective management of operating and capital costs, is improving profitability.
And finally, we took another significant step in unlocking unrealized, or unrecognized asset value within Devon through the formation of a new midstream business and the planned repatriation of an additional $2 billion at very favorable tax rates. So at this point, I’d like to turn the call over to Dave Hager for a more detailed review of our quarterly operational highlights.
Dave?
David Hager
Thanks, John. As John mentioned, the third quarter was one of solid execution by our asset team, resulting in strong oil production growth.
This growth in oil production, combined with effective cost management, allowed us to expand margins and grow cash flow. Looking specifically at costs, our results year-to-date have benefited from our supply-chain efforts and improved drilling efficiencies.
As a result, our service and supply costs have declined by roughly 5% compared to 2012. In addition, we are realizing cost savings through drilling efficiencies in each of our core operating regions, allowing us to complete our full year programs with fewer rigs than originally budgeted.
Due to this enhanced productivity, as of the end of September, we had reduced our rig count by 10% from last quarter to 64 operated rigs. Now let’s take a closer look at some of the key operating highlights in the third quarter.
Beginning with the Permian, our production averaged a record 82,000 barrels of oil equivalent per day with light oil accounting for 60% of our total volumes. We are currently running 23 operated rigs in Permian and by year end, we expect to have drilled more than 350 wells for the full year.
In the Delaware Basin, our Bone Springs horizontal program continues to be a key driver of our Permian oil growth. We currently have 12 operated rigs working in the play.
In the third quarter, we brought 24 Bone Springs wells online with average 30-day IP rates of 609 barrels of oil equivalent per day, of which more than 70% was light oil. These production results are about 20% better than our tight well profile.
With a large portion of our acreage de-risked and in the development stage, pad drilling is playing an increasingly important role in our development plans. With current well costs already meeting our type well economics, we expect the efficiencies of pad drilling to further reduce costs and enhance our already outstanding Bone Springs returns.
We have roughly 1,400 Bone Springs locations identified, and we fully expect that our ongoing drilling and geologic work in this top-tier light oil play will allow us to further increase our inventory over time. Also in Delaware Basin, there have been a number of positive Wolfcamp wells drilled by other operators around our acreage in both Ward and Reeves County.
In the fourth quarter, we expect to begin completing our first horizontal Wolfcamp test in Ward County. Keep in mind, our 2013 program in the Delaware Basin has been focused on our low-risk high return oil development opportunities in areas like the Bone Springs but we are paying close attention to the exploration drilling and de-risking industry is doing in the Delaware-Wolfcamp.
We are well positioned in the Delaware-Wolfcamp with approximately 140,000 net prospective acres. Across the entire Permian Basin, Devon has over 300,000 net acreage prospective in the Wolfcamp.
This includes our Wolfcamp Shale position and the Southern portion of the Midland Basin where we have been adding to our position and now have more than 100,000 net acres. We continue in full development mode with our five written [ph] program.
During the third quarter, we spud 35 new horizontal Wolfcamp Shale wells and brought 26 online with average 30-day IP rates of 400 barrels of oil equivalent per day of which nearly 75% is light oil. Landing and completing our wells in Lower Wolfcamp continues to yield consistent production results that are in line with our tight well profile for this play.
On the drilling front, we continue to improve returns in this play by reducing drilling time and completion costs. During the third quarter, our average well costs came in at $5.5 million about 10% below our tight well.
We have approximately 800 undrilled locations in this light oil resource play and we expect to expand our inventory over time as we begin to de-risk our recently added acreage. In summary, Devon’s 1.3 million net acres in the Permian represents one of the largest and highest quality acreage positions in the industry.
We continue to be one of the most active Permian drilling and as a result we are on-track to deliver basin wide oil production growth of more than 30% in 2013. We have established thousands of undrilled low-risk locations in the Permian and our inventory continues to grow with exciting opportunities in emerging plays like the Delaware-Wolfcamp.
Shifting to the Mississippi and Woodford trend in North-Central Oklahoma, we are excited about the progress we are making across our 650,000 net acre position. We have 15 operated rigs running in trend.
In the third quarter, we tied in 49 operated wells across the trend, many of which were drilled in previous quarters. We continued a very active program in the Woodford Oil Shale in the third quarter and spud 57 new Woodford oil wells.
During the quarter, we tied in 10 Woodford wells on our joint venture acreage with initial 30-day production rate averaging 535 barrels of oil equivalent per day, of which more than 75% was light oil. This is well above our tight curve for the trend.
These results include the Jardo [ph] that achieved an average 30-day IP rate of nearly 2,200 barrels of oil equivalent per day, including 1,700 barrels of oil. Even excluding this outstanding oil, our third quarter Woodford program exceeded our tight curve for the trend.
Seismic has played a key part in the early success for our Woodford drilling. Of the 27 Woodford wells brought online this year on our joint venture acreage, we have seen more than a 100% increase in 30-day IP rates in our wells drilled with the benefit of 3D seismic as compared to those wells drilled without.
We are also achieving some encouraging results in Mississippi Lime on our joint venture acreage during the third quarter. Our Miss Lime results were highlighted by 14 wells brought online with average 30-day IP rates of nearly 500 barrels of oil equivalent per day, including 345 barrels per day of light oil.
While our Miss Lime results across the trend continue to vary depending on the location, reservoir quality, landing zones and completion techniques, we fully expect the integration of 3D seismic into our geologic modeling to optimize our Miss Lime results over time. To-date, we have acquired 3D seismic over majority of our acreage inside the joint venture area.
We’re also seeing encouraging results outside the JV in both the Miss Lime and the Woodford oil shale formations. In Grant County where we have approximately 79,000 net acres, we completed the well subsequent to quarter end in the Miss Lime with an average 24-hour IP rate of more than 920 barrels of oil equivalent per day, including over 800 barrels of oil.
Additionally, during the quarter we drilled our first Woodford oil shale well in Grant County. This well had a 30-day IP of 225 barrels of oil equivalent per day and was drilled without the benefit of seismic.
With this well confirming the existence of an oil [ph] charged Woodford interval comparable to that of our wells in the JV area, we are excited about obtaining seismic in Grant County. While it’s very early in our testing this acreage, these results demonstrate the productive capability of the Woodford and Miss Limes in the north of our JV core.
Combining our Woodford oil shale and Miss Lime results, our third-quarter production across the trend averaged 8,800 barrels of oil equivalent per day; that’s 65% increase over the second quarter. This production growth is especially impressive given our inventory of over 100 wells yet to be tied in or completed.
As of mid-October, this included 19 wells held up by pad drilling, 27 wells awaiting completion, 37 wells currently in some phase of completion and another 25 wells awaiting infrastructure buildout. While this level of inventory is to be expected in an emerging play, we believe the backlog will level off early next year as more and more of our midstream infrastructure is placed in service.
We exited the third-quarter production accelerating to 10,700 barrels of oil equivalent per day, putting us on track to approach our 2013 exit rate of 15,000 BOE per day for the Mississippian Woodford trend. Also on the emerging play front, our Rockies oil program, the Powder River basin delivered excellent results in the quarter with oil production increasing 34% over the year ago period to 11,000 barrels per day.
In the third quarter, we tied in two Frontier wells with initial 30-day production rates averaging 740 barrels of oil equivalent per day, of which more than 85% was light oil. We are also excited about two additional high-rate oil wells we brought online earlier in the fourth quarter targeting the Frontier formation.
The 24-hour IP rates for these two wells each averaged in excess of 1400 barrels of oil equivalent per day, with light oil comprising almost 90% of the production. In addition, we are currently completing our first two long lateral wells in Powder River basin and should have those well results by our next call.
To date we have identified approximately 600 risk locations across our Powder River acreage, and we expect this inventory to grow as we continue to derisk as the emerging light oil opportunity. Shifting to our thermal oil projects in North-eastern Alberta, third-quarter production from our two Jackfish projects averaged roughly 46000 barrels of oil per day net of royalties.
The significant improvement in heavy oil pricing boosted our Jackfish price realizations by 36% over the previous quarter, helping to improve our cash margins for the quarter. Jackfish 1 production averaged 29,600 barrels per day during the quarter due to a step-up in royalty rates as a result of reaching payout in June.
However continuing the improvement in our steam oil ratio allowed us to achieve average gross production of 36,000 barrels per day in the quarter, exceeding the facility’s nameplate capacity of 35,000 barrels a day. As we indicated in our last quarterly call, Jackfish 2 was taken down during the third quarter for scheduled maintenance.
The plant turnaround was completed ahead of schedule on budget and with an accelerated ramp up. This is a significant improvement compared to previous turnarounds at our Jackfish facilities and is a testament to the hard work and expertise of our thermal project team.
Since each SAGD facility requires plant maintenance downtime every 2 to 3 years, efficiency gains on turnarounds lead to higher old cycle returns. Also of note at the end of the third quarter, we began steaming a new well pad at Jackfish 2.
This pad at peak production is expected to contribute up to 8000 barrels of oil per day gross from nine new well pairs. Full ramp-up of the pad is expected to occur over the next 12 months.
Our Jackfish remain ahead of schedule and on-budget with nearly 80% of the project complete. First team is anticipated in the third quarter of 2014; roughly one quarter sooner than originally expected.
Moving now to the Cana Woodford Shale in Western Oklahoma, our third quarter production averaged a record 57,000 barrels of oil equivalent per day. Our expanded processing facilities help to increase oil and liquids production to 21,000 barrels per day, up 58% compared to the prior year quarter.
Liquids now comprise nearly 40% of total Cana Woodford production. And with our drilling activity focused in the very best parts of the liquid rich core, we are producing a more valuable liquid stream.
Combining with our strong liquid rich production growth and low operating cost, Cana Woodford unit operating margins increased 39% year-over-year. Our record production performance in the quarter was underpinned by excellent drilling results.
We brought 39 operated wells online with 30-day IP rates of 950 BoE per day including 475 barrels of liquids per day. These well results exceed our play type curve by nearly 15%.
In addition, we continue to improve our drilling efficiency at Cana. In just this year alone, we have seen a 25% improvement in the number of days from spud to rig release.
This improvement in drill time will allow us to finish our 2013 program of nearly 150 wells with only nine operated rigs, three less than our original budget. And finally, in the Barnett Shale in North Texas, our liquids rich drilling program continues to generate competitive returns.
Our expanded capacity at our Bridgeport facility helped drive oil and liquids production increased 15% year-over-year to 58,000 barrels per day, a record production level. Our initiatives to reduce lime pressure and utilize artificial lift, to-date, have been very successful with net production in the third quarter averaging 1.4 Bcf equivalent per day.
So, in summary, we had another strong quarter of execution across our entire North American Onshore portfolio. The core focus areas, that I discussed today on the call, are delivering highly economic and robust production growth for Devon.
If you apply a relatively conservative oil to natural gas price ratio of 20:1 to Company-wide production in the third quarter, our top-line growth increased nearly 10% year-over-year. With that, I’ll turn the call over to Jeff for the financial review and outlook.
Jeff.
Jeff Agosta
Thanks, Dave, and good morning, everyone. I will take you through a brief review of the key drivers that shaped our third quarter results and, where called for, provide updated guidance.
I will also elaborate on the good news about our cash repatriation plan that John mentioned earlier. Looking first at production, in the third quarter, we produced approximately 64 million oil equivalent barrels or about 691,000 equivalent barrels per day.
This was in the top-half of our guidance range and most importantly was underpinned by strong high margin oil growth. For the quarter, Company-wide oil production averaged 165,000 barrels per day, an increase of 16% compared to the same period last year.
As John detailed earlier, this growth was driven entirely by our US properties with light oil production up 38% year-over-year. Looking at the fourth quarter, we expect strong oil growth in the Permian Basin and the Mississippi and Woodford trend to continue, driving US light oil production up more than 30% compared to the fourth quarter of 2012.
This impressive growth will increase our expected total Company-wide oil production next quarter to a range of 170,000 to 175,000 barrels per day. After taking into account declines in dry natural gas, we expect total Company-wide production in Q4 to range between 680,000 and 700,000 BoE per day.
Overall, this keeps us on-track to deliver on our full-year production guidance of 250 million to 254 million BoE. Moving to price realizations, overall our third quarter regional price realizations by product were generally in line with our expectations.
Looking specifically at Canadian oil prices, in the third quarter higher season demand and improved flow rates on export pipes for heavy oil out of Canada, improved our realizations to 75% of WTI or $80 per barrel. This represents the best oil prices we have seen for Canada since 2009.
Even with this excellent result, the supply and demand dynamics for Canadian crudes remain very tight. In fact, subsequent to the third quarter, increased supply from new oil sands projects, refinery downtime and outages at third party pipelines have resulted in downward pressure on Canadian oil prices.
Based on what we've seen so far in October and November trading, we now expect our Canadian oil realizations to temporarily decline to a range of 50% to 60% of WTI in the fourth quarter, before the impact of hedges, offsetting the lower pricing of the attractive Canadian heavy oil hedges we have in place. For the fourth quarter, we have 40,000 barrels per day of WCS blended crude swap at a discount to WTI of $22 per barrel.
These attractive hedges cover well over 50% of our expected thermal oil production output for the quarter. Looking ahead to 2014, the increase in the heavy oil capacity at BP’s Whiting refinery will improve demand and increased export pipeline and rail capacity will help alleviate transportation bottlenecks.
These favorable catalysts should reduce the overall pricing volatility of Canadian crudes and support the narrowing of the differentials as we go through 2014. Looking briefly at natural gas, the only notable change to our previous guidance is a minor adjustment to account for acre differentials in Canada.
Now that we are seeing improved flow rates out of Canada, export flow rates out of Canada we expect Canadian gas price realizations to improve in the fourth quarter to a range of 75% to 85% of Henry Hub. For natural gas liquids, we expect our companywide fourth quarter price rationalizations to remain essentially flat with the last few quarters ranging from $25 to $27 per barrel.
Turning now to our midstream business, once again our marketing and midstream operations delivered excellent results, generating $137 million of operating profit in the third quarter, a 25% increase compared to the third-quarter of last year. Increased throughput at our newly expanded Cana and Barnett processing facilities, higher natural gas prices and strong cost controls drove our solid performance.
Based on the results for the first nine months and our outlook for the fourth quarter, we now expect our full year operating profits to come in between $475 million and $525 million. This is a $25 million increase over our previous guidance.
Moving to expenses, in the third quarter our total pretax cash costs came in at $15.13 per BOE. This result was right in line with our expectations, maintaining cost essentially flat with last quarter.
This is an especially positive result considering the negative volume impact and higher LOE costs associated with our plant turnaround at Jackfish 2 during the quarter. Overall our cost structure remains one of the best in the industry even as we transition our portfolio to higher margin or higher cost oil production.
Going to the bottom-line our third-quarter performance translated into non-GAAP earnings of $526 million or $1.29 per diluted share. This represents a 47% increase in earnings per share year-over-year and comfortably exceeded Wall Street expectations by $0.09.
This level of earnings translated into cash flow per share of $3.89, also exceeding the street’s expectations. Before we open the call to Q&A, I will conclude my remarks with a quick review of our financial position.
During the third quarter, Devon generated operating cash flow of $1.6 billion, an 18% increase compared to the year ago quarter. When you include the nearly $300 million of proceeds from the closing of minor asset sales during the quarter, our cash inflows totaled $1.9 billion.
These cash inflows comfortably funded our total CapEx of 1.7 billion. It is also important to note that for the full year our total capital spending, which includes E&P, midstream and corporate capital remains on track to be near the midpoint of our guidance we provided at the beginning of the year.
From a balance sheet and liquidity perspective we remain exceptionally strong. We exited the quarter with a net debt to adjusted cap ratio of only 22% and cash balances of $4.3 billion.
Of these cash balances, approximately 3.6 billion resides in subsidiaries outside North America. As John mentioned earlier, our tax position now affords us with the opportunity to efficiently repatriate an additional $2 billion of cash to the US around year end.
We expect NOLs and other credits to limit our tax rate on this repatriated cash to somewhere in the 46% range. By year-end we will have repatriated $4 billion of foreign cash at an estimated tax rate of approximately 5%.
To provide some perspective on the significance of this, you might recall after divesting our international assets in 2010-11 we guided toward a tax rate of about 20%. The lower actual tax rate on the amount repatriated to the US and the tax-free transfer of $500 million to Canada we made earlier in the year will result in an incremental $700 million benefit to Devon shareholders, roughly the equivalent of about $1.75 per share.
In summary, it was another solid quarter for Devon. We delivered strong oil production growth.
We expanded our margins through growth in light oil. We maintained strong cost controls and we remain positioned with one of the best balance sheets in the industry.
So with that, I will turn the call back over to Vince for the Q&A. Vince.
Vince White
Thanks Jeff. (Operator Instructions).
With that operator, we’re ready for the first question.
Operator
(Operator Instructions). Your first question comes from Scott Hanold of RBC.
Your line is now open.
Scott Hanold – RBC
Thanks. Good morning.
Looking at the Permian Basin, the Southern Delaware, you know, kind of a couple of questions. You talked about expanding your inventory there, can you give us a little bit more color on that, like, how many of the benches down there you all have tested and which ones you think are going to be prospective and which ones in your current well count?
And then the other thing is, I think you all just recently acquired Forest Oil’s acreage down there, can you give us a little bit of thoughts on what you’re seeing there?
David Hager
Yeah, Scott, you’re talking about the Southern Midland Basin, I think, aren’t you? Not the Delaware Basin.
Scott Hanold – RBC
Oh, I’m sorry if I said Delaware, yes, you’re correct.
David Hager
Yeah, right. Yeah, we have tested and there’s obviously a nomenclature issue within the industry that we prefer to call it that we have tested both the Middle and the Lower Wolfcamp, those are the primary prospective zones on our acreage.
We are right now, for the most part, have very little across the acreage, but for the most part we are completing in the Lower Wolfcamp and we believe that allows us to actually frac up to the Middle Wolfcamp as well. So, by industry nomenclature, I think that would be completing more in the F and then the frac would contribute on up through the D in there.
Regarding the Forest acreage, that’s the part that I didn’t mention in my comments earlier. That’s the additional acreage that we acquired.
It’s a little over 50,000. I think, around 53,000 or so total.
We haven’t drilled any wells on that acreage yet, we will start drilling those next year. And that’s the comment I was making that I do believe that we’ll expand our inventory.
We have not expanded our inventory at all in the comment that I gave to you already on the – but we fully anticipate that it’s going to work and will be additive to the overall position.
Scott Hanold – RBC
Okay. And just to again clarify on your current inventory count in the Southern Midland Basin, I think it was 800 locations.
Is that assuming an Upper and a Lower Wolfcamp?
David Hager
It is considered what is appropriate to complete in each of those. And we have not really plugged into there that we would have multiple completions at the same location.
So, that’s a single completion at each of our locations. It is possible, through time, we may see that we may complete in more than one zone from the same location but we haven’t included it in our location count.
Scott Hanold – RBC
Okay. Because I think some of your competitors or peers are talking about anywhere from two to four different formations prospective in each zone location, is that –
David Hager
That’s certainly a possibility through time and we have the same opportunities our peers do, it’s just how we choose to classify our locations, perhaps a little more conservative.
Scott Hanold – RBC
Okay. And based on your acreage contracts, do you have to drill lowest formation to hold everything.
David Hager
Scott, I’d have to check on that. That is typical that you would, but I’d have to check – let me think about it whether it – I’m going to – yeah, I’ll give you some clarification here, they are saying we are in the same zones.
So it doesn’t -- don't think we have to. Now more I think about that, I think that’s right that if drill in the operator, we still the hold the lower.
Operator
Your next question comes from Vinnie Wong of Morgan Stanley.
Unidentified Analyst
I know that Crosstex deal hasn't closed yet, but can you tell us how you are thinking about maybe the drop-down pace of assets into the MLP just so -- you mentioned the benefit of the combination versus doing IPO in terms of speed to market?
John Richels
Vinnie [ph], there's really a couple of different drop-downs that we can do in the MLP. As you know, we put half of our assets into the GP and half into the MLP.
So there will be a continuing drop-down from the GP to the MLP of interest in our midstream company. And then we do have other assets, the one that we flagged at the time – other assets that we didn't put into the MLP, one of the assets that we've flagged at the time was our interest in the Access Pipeline, which is the pipeline that services our Jackfish and Pike acreage and also has third-party volumes from other operators in the area.
And that's certainly something that we can drop down. When we do that, it's a little bit up in the air right now, and of course, we are constructing that.
I think it's going to be completed by the end of 2014 roughly and third quarter 2014. And so a 2015 drop-down is certainly possible.
We'll have to kind of take stock of things at the time that we finish it. I think the really important part and the really exciting part for us is that not only we kind of got a market valuation of what those assets are, but in the future it gives us a lot of flexibility around building new assets, dropping down some existing assets that we haven't put in yet, and also doing acquisition and by doing that it accelerates the value over what we'd otherwise have seen.
Unidentified Analyst
Okay, great. And just my second question is in regards to $2 billion in cash being repatriated, can you update on what you are thinking there and particularly where you guys want to put it?
John Richels
As Jeff mentioned, it's likely to be around year end before we can repatriate those funds. Vinnie, as you may know and most of the folks on the call are probably familiar with the factors that we've talked about in the past that we take into account as we allocate our capital and the objective we've always enunciated is to optimize cash flow for debt adjusted shares.
So, when we bring that cash back around the end of the year, we'll allocate using the same parameters. We're right now in the middle of and – or continuing to develop our 2014 capital budgets and we'll do that over the next couple of months.
And as we move into 2014, we'll finalize our capital allocation decisions. At that time, share buybacks are always included in our consideration to capital investments and we’ve got a great track record of buying stock back over the years.
But to give you any more definite guidelines around that right now would be a little premature.
Operator
Your next question comes from Jeffrey Campbell, Tuohy Brothers Investment.
Jeffrey Campbell – Tuohy Brothers Investment
Questions on the Woodford oil play. My first question is as I wasn't entirely sure from what I heard, is all of your current drilling on JV lands or are you also doing some drilling aside from the Grant County, kind of sounds like a wildcat, are you doing any drilling on your non-JV acreage?
David Hager
This is Dave. We just have one rig that's working outside of the JV.
The rest of the rigs are working within the JV. And that's the rig in Grant County.
Jeffrey Campbell – Tuohy Brothers Investment
And my other question with regard to the Woodford, I'm looking at the map of your acreage in the area. Do you believe that you have prospectivity in any of the other counties besides Grant?
I'm thinking non JV again, like maybe Kay or Sage County.
David Hager
Well, it's possible. We need to drill some wells over there and determine it.
Again, we are seeing such an advantage here of getting 3D seismic and that's what's really helped us out dramatically within the JV. We're going to drill a few wells up here in Grant and Kay County without 3D just to – 3D in and of itself costs a fair amount of money.
And so we want to make sure that we have a working petroleum system up there before we actually spend the money on the 3D. We now have in Grant County enough confirmation that through the wells that I discussed that we are shooting 3D up there.
We will be going through the same process in Kay County and that – the overall comment that I’ve made before is that we have 650,000 acres in total in the Mississippi and of that we believe there are sufficient thickness of the Woodford to have potential prospectivity across 400,000 of that 650,000 acres. To-date we feel we have de-risked 100,000 of that 400,000 acres.
So, we have the thickness across the 400,000 but there are other elements that factor into there as far as the maturity of the oil, do you have sufficient permeability, et cetera, and that’s what we’ll have to determine across that other 300,000 acres we’re talking about, some of which is in Grant and some of which is in Kay.
Jeffrey Campbell – Tuohy Brothers Investment
Okay. Great.
That was great color. Thanks very much.
Operator
Your next question comes from Matt Portillo of TPH. Your line is now open.
Matt Portillo – Tudor, Pickering & Co.
Good morning, guys. Just a quick question for me in regards to your oil growth guidance for Q4.
Looks like kind of a step up on a quarter-over-quarter basis, is pretty flat especially with the ramp-up in the Canadian volumes. So, I was just wondering if you can comment maybe where we’re seeing a little bit of a deceleration in the growth into year-end or if that was in line with your planned expectation going to the fourth quarter here?
David Hager
Yeah, Matt, it’s a little bit less than we guided to last quarter. The first thing I want to make clear to everyone, though, about this is our wells are delivering exactly as we anticipated.
I went through it area-by-area. The capabilities of the wells are there.
That is not the issue. The issues – there’s a couple of other issues that have factored into it though overall.
First, we are seeing some down time with our ongoing production in the Permian, especially as related to electrical submersible pump that we’re running in all of these. Our run time of those has been a little bit less than we anticipated.
We’re working through that issue as we speak but that has caused our base production to fall a little bit short of what we anticipated. Nothing to do with the productivity of the wells, just the efficiency of the pump.
Secondarily, in the Rockies because of the success we had with the Rockies drilling program, we took a little bit of capital out of CO2 that we’re going to expand, that were going to deliver a few thousand barrels a day and kept a rig running in the Powder River Basin because of the outstanding results we’re getting there. Those volumes, associated with that rig, will show up next year but not this year.
And then finally, because of the stronger prices when we put our projection out there that we were seeing in Canadian oil because of the stronger realizations we anticipated royalties would be a little bit higher. And so that would cause the net production to go down a little bit as well.
But having said all that, I want to make sure that you understand the US oil growth in Q4 is going to be greater than 30% versus Q4 of 2012. So we’re still having very, very strong oil growth, it’s just some minor issues like that, these have nothing to do with the productivity of the well, that have caused it to decrease it a little bit.
Matt Portillo – Tudor, Pickering & Co.
Great. Thanks for the clarification there.
And just in regards to some of the initial well results you’ve seen in the Woodford. I was wondering if you could potentially compare the rates of return you’re seeing on your Woodford programs versus your Southern Midland program?
And if you continue to see strong initial rates here, in line with your or above your type curve could we potentially see capital allocated away from the Permian into the Woodford or an acceleration in Woodford drilling? Thank you.
David Hager
Well, we’re going through that entire evaluation process right now, of comparing the returns. And we’re obviously a little bit less in the overall maturity of the program in the Woodford then we are in the Southern Midland Basin.
But having said that, we’ve had some outstanding results this quarter with well, well above the type curve and, of course, highlighted by the Jardo [ph] that had a 30-day IP of 2,200 BoE per day. So we like both these plays an awful lot.
And to ask me to make a decision between one or the other is kind of tough because they are two of our top plays and we like them both but we’re certainly very pleased with the Woodford results.
Matt Portillo – Tudor, Pickering & Co.
Thank you very much.
Operator
Your next question comes from Arun Jayaram of Credit Suisse. Your line is open.
Arun Jayaram – Credit Suisse
Good morning. John, it’s been a busy year on the strategic front.
By year end you will complete in a two major repatriations and you’ve got the midstream transaction. So just wondering if you could maybe comment on where Devon is in terms of the overall portfolio.
Anything else that you are working on in terms of the portfolio changes, or is this the asset base going forward?
John Richels
Well, Arun, as you know, in this business that's a constant. We are always looking to bring good opportunities into the asset base and sometimes that means that other opportunities don't look as attractive anymore and you move them out.
So, that's not something that we – that's a continuum. We're not at the end of it.
We always got to look at that. So, it's an ongoing process to continue to try to increase our productivity as a company and our value for our shareholders.
It's something we're looking at all the time.
Arun Jayaram – Credit Suisse
John, just to maybe elaborate on that. At one time you guys had – was doing some analytical work around Canada, maybe a spin-off or something like that.
Have you come to a decision on that, or are you still evaluating that?
John Richels
I think these things are all things that we're evaluating all the time, and I think you know that in our history, we've proven that we're not afraid of making bold moves when we have to, but a lot of things people talk about and reflect on from the outside don't always add long-term value particularly when you look at taxation and everything else that's involved. So we're always looking at how we might bring value forward, and as we've previously said, we're not leaving any stone unturned.
But we're not going to do things that – we're only going to do things that add long-term value and we're not going to take action simply for action's sake. So, these are things we're always looking at, but sometimes they’re not quite so simple.
Arun Jayaram – Credit Suisse
That’s helpful. Dave, I wanted to see if you could elaborate a little bit more on this ESP-related downtime.
Is this something that could have a knock-on effect as we think about 2014, or is it more isolated to the fourth quarter?
David Hager
Well, it's something that we're working on right now, and we think it’s very solvable. Basically, we're running these ESPs in an unconventional environment, and frankly, running a lot of sand through these ESPs, which as you can imagine, running sand through pumps is not a great thing for long-term life.
But we are working with some of our vendors on ways that we can get a better design out there. We're also working on ways that we can improve the efficiency of replacing these ESPs, and so, I don't think it's going to have a long-term impact.
We have a special team, I can tell you internally, that’s working at very hard along with our vendors. And I think it's something that we're going to come to a good answer on here in the next three or four months.
And frankly that's just one of the things that contributed to it. The other I mentioned was a change in the Rockies program to the additional rig and also the impact of potentially higher royalties due to improved realizations in Canada.
So, I wouldn't overplay that. It's just one of the several factors.
Arun Jayaram – Credit Suisse
My last question would be just what your new midstream spending levels could look like post the closing of the transaction?
John Richels
That of course is dependent upon where we choose to spend capital and so we're going to – we're in the processing of working our 2014 capital budget. And until we've got the upstream piece we won't know exactly what the midstream piece is, but directionally surely, I mean, we certainly expect it to be down.
Operator
Your next question comes from Charles Meade of Johnson Rice.
Charles Meade – Johnson Rice
Going back to the Woodford, can you give us an idea if that 75% to 80% oil cut that you see in the Jardo [ph] well is representative of what the oil gas spilt is for the rest of your wells there?
David Hager
Well, in all of our wells in the Woodford, it's going to have a higher oil cut early in the life, which certainly is beneficial from a rate of return and NPV standpoint. Although over the life of the well, we anticipate they will become more gassy and the ultimate -- and when you looked at total EUR, it will probably split about equally, one-third each for oil, natural gas liquids, and natural gas.
Charles Meade – Johnson Rice
And then I know it's early in the play and clearly this Jardo [ph] well is a great well, but I was wondering if you could elaborate a bit on if this well – if you had an idea ahead of time that this well might really perform well, whether because it's a long lateral or whether there is something you saw on the seismic that gave you an indication whether this was just a surprise to everybody?
David Hager
Well, it was a long lateral, so that certainly helped but there also were some other geological characteristics which, of course, I’m not going to tell you that we had observed ahead of time and we think that that benefited that. Your obvious follow-on, is it repeatable, I’m sure.
And to some degree, yes, but it’s not going to be – we’re not going to be able to drill those wells everywhere across the acreage but we think we have a good idea for what allowed that and we’ll have some of those type wells across our acreage position, we think, again.
Charles Meade – Johnson Rice
Dave, you understood exactly what I was after. Thank you for the added detail.
Operator
Your next question comes from David Tameron of Wells Fargo. Your line is now open.
David Tameron – Wells Fargo
Good morning. Can you guys just talk about, in the Permian can you – and you addressed this a little bit but you can you give me some color on Delaware versus Midland, the differences between the two and kind of the rates of return and well cost?
David Hager
Are you talking specifically, David, about the Wolfcamp or across our entire portfolio?
David Tameron – Wells Fargo
No, I mean, just what you’re seeing on the Bone Springs versus you know – and I was just studying the wells you put in the press releases as far as the Permian well and the Bone Spring well look to have higher IPs by couple of hundred barrels or so, I guess, close to 300 barrels, on those 30-day rates. And I kind of looking at that versus –
David Hager
Right. Yeah, in general to answer your question, the Bone Springs are our highest returns in our portfolio in the Permian Basin and amongst the highest in our entire portfolio as a company.
Although all of them generate strong rates of return, the Bone Springs are a little bit better, no question.
David Tameron – Wells Fargo
Okay. Alright, I’ll leave it at that.
That’s all I got. Thanks.
Operator
Your next question comes from Mark Hanson of Morningstar. Your line is now open.
Mark Hanson – Morningstar
Good morning, guys. Two quick questions for you.
First, how would you characterize the Miss Lime’s performance relative to your expectations based on results to-date? I know you’ve given an awfully good color this morning across the trend, both, Woodford and Mississippi Lime.
Just seems, from commentary you provided, you’re a bit more enthusiastic about the Woodford at this point?
David Hager
Well, we still like the Miss Lime an awful lot. It is meeting out type curve expectation, certainly within the JV and is actually above our type curve expectations slightly.
So we’re very happy within the JV. North of the JV and in Grant and Kay County we’ve had mixed results.
I had talked about one very good well that we had out there in the past quarter. We’ve had some that are not as good.
But you have to understand, this is done without the benefit of seismic. So, the primary thing we’re trying to do up there outside of JV right now is see if we have enough evidence to have a good strong working petroleum system and which we now are confident in Grant County that we do have that.
And now that we have that, we’ll shoot 3D up there and we’ll really refine where we’re drilling those wells and I would anticipate the results to become much more consistent and to improve with the benefited of 3D. But overall as far as the Miss goes, it is meeting our expectations just at this Woodford particularly within the joint venture area.
Now, we’ll have at least one well up in Grant County that’s somewhat encouraging as well. It’s working spectacularly.
Mark Hanson – Morningstar
Great. Very helpful.
And then the second question, just with your Permian rig count, I saw that it dropped by a meaningful amount, I don’t know if that’s related to the ESP issues, but any more information on where rigs were dropped and the things –
David Hager
Yeah, it has nothing to do with the ESP issues at all. We dropped our rig count because we become significantly more efficient in drilling our wells.
We executed our entire program for 2013 and we could execute it with less rigs. So, if we had kept the same amount of rigs we would have overspent our capital for this year.
And so we were just exercising capital discipline to stay within the overall capital by reducing our rig capital. We executed the program we had intended to this year.
Mark Hanson – Morningstar
Great to hear that. Thank you.
Operator
And your last question comes from Biju Perincheril of Jefferies. Your line is now open.
John Richels
Biju, we apologize for butchering your name.
Biju Perincheril – Jefferies & Co.
That’s quite alright; I’m used to it. The question I had was on the Wolfcamp.
It looks like the 30-day rate this quarter was maybe a little bit lower than what you had in the past. And I was just wondering if that’s because you’re changing anything around on the completion front or is that just the normal variability?
David Hager
Nothing significant there, Biju. The change around, it’s just what pads we happen to be bringing on this quarter but I wouldn’t read anything else into it.
Next quarter, it could go back up just as easily as it went down a little bit this quarter, nothing significant there.
Biju Perincheril – Jefferies & Co.
Aerially or geographically, were you drilling in the generally same areas?
David Hager
Yes, generally we're drilling in the same areas still. One comment I want to make to Scott Hanold, asked a question that kind of stopped me earlier about holding all rights and the reason, I wasn't thinking about it as clearly as I should have been.
The answer is it's kind of an academic question, because we're actually completing in a lowest Wolfcamp zone. So because we are completing in the lowest Wolfcamp zone, we're going to have all the rights above that, so it's really an academic issue.
We'll hold all that.
Biju Perincheril – Jefferies & Co.
And one question along those lines is do you have any plans in the near-term to test different horizons at the same location?
David Hager
Nothing immediate. We recognize the prospectivity there, but we are right now just delineating our entire acreage position.
John Richels
Well, folks I'm showing the top of the hour. So that concludes today's call.
As usual, our investor relations staff will be around the rest of the day to answer any questions that didn't make it into the call or if you come up with other things during the day. So before signing off, I'd just like to go over a few key takeaways.
First, our core assets are performing very well leading to higher oil weighting for our portfolio. This is driven by the 38% year-over-year growth in light oil production from our U.S.
portfolio. Results from our emerging U.S.
light oil plays and long-term investment in Canadian thermal oil are providing visibility on the next leg of oil growth for Devon. Our pursuit of high margin production is improving profitability and we are doing excellent job of controlling, operating and capital costs.
By year end, we will have repatriated $4 billion of cash at very favorable tax rates translating into about $1.75 per share benefit to Devon shareholders, and finally, we took another significant step forward in unlocking unrecognized asset value within Devon through the formation of our new midstream business. Going forward, our approach to the business remains unchanged.
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. So, we look forward to talking with you again on the next call, and thank you very much for joining us today.
Operator
And this concludes today's conference call. You may now disconnect.