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Devon Energy (NYSE:DVN)

Q2 2013 Earnings Call

August 7, 2013 10:00 a.m. ET

Executives

Vince White – SVP, Communications

John Richels – President and CEO

David Hager – EVP, Exploration and Production

Jeff Agosta – CFO

Analysts

Arun Jayaram - Credit Suisse

Doug Leggate - Bank of America Merrill Lynch

Brian Singer - Goldman Sachs

[Sue Lin] - Robert W. Baird

John Herrlin - Société Générale Americas Securities

Rehan Rashid - FBR

Charles Meade - Johnson Rice

Operator

Welcome to Devon Energy’s second 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 second quarter earnings call and webcast. Today’s call will follow our usual format. I’ll cover a couple of preliminary items, and then our president and CEO, John Richels, will comment on the quarter. Following that, Dave Hager, our chief operating officer, will provide the operations update, and then we’ll have a financial review by our CFO, Jeff Agosta. We’ll follow that up with a Q&A session.

And I’ll point out that our executive chairman, Larry Nichols, as well as Darryl Smette, who is the head of marketing midstream and supply chain, are both with us today to join in the Q&A. We’ll conclude the call after one hour.

During the call today, we’re going to update some of our forward-looking estimates based on the actual results that we’ve seen in the first half of the year our revised outlook for the second half of 2013, but we are not planning to issue a new 8K. We will, however, post any updated estimates that we provide during the call today on the guidance page of our website.

If you go to our website, you can just click on the guidance link, look in the investor relations section, and all of our guidance is summarized there.

All references today to our plans, forecasts, expectations, and estimates are forward-looking statements under US securities law and they are of course subject to a number of assumptions, risks, and uncertainties. Many of these are beyond our control. And I’d point out that these statements aren’t 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 and when we do that, we’re required to provide certain related disclosures. Those can be found on Devon’s website.

Before I turn the call over to John, I’ll point out that both earnings and cash flow for the second quarter significantly beat Street estimates. Our non-GAAP earnings climbed to $1.21 per diluted share. That’s more than double the earnings we reported in the year ago period, and it exceeded the Wall Street consensus by about 30%.

Cash flow climbed to $1.4 billion for the quarter, the highest level in the last six quarters, and that also comfortably beat Street expectations. Overall, from both an earnings and cash flow perspective, it was an excellent quarter for Devon.

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

John Richels

Thank you, Vince, and good morning everyone. As Vince just mentioned, we had an outstanding second quarter. In addition to benefitting from the substantial improvement in realized prices during the quarter, we exceeded the top end of our production guidance.

At the same time, our year to date cost metrics are tending towards the low end of the forecast range. This is all strong evidence of the successful execution of our business plan as we continue to grow our high margin oil production.

Let me begin today by reviewing some of the highlights of the quarter. In the second quarter, we increased company-wide oil production 14% compared to the second quarter of 2012, and 4% compared to last quarter. This growth was driven entirely by high-margin light oil production from our U.S. assets, which increased a robust 36% year over year.

With the success we’ve had in growing our oil production, we now expect liquids production to exceed 45% of total volumes by year end, and that’s up from just 30% just a few years ago.

In the second quarter, total company-wide production from our North American asset base is at an all-time record, averaging 698,000 equivalent barrels per day. This exceeded the midpoint of our guidance by 3% and topped the upper end of our forecast range by 8,000 barrels per day.

Based on the results of the first half of the year, we now expect our full year 2013 production to be near the top end of our guidance range for the year. Jeff will cover the production guidance in a little more detail later in the call.

When you examine our operating results in greater detail, you’ll find that we had terrific execution across all of our core focus areas. The most notable growth in the second quarter came from our massive 1.3 million net acre position in the Permian Basin, where oil production increased 32% year over year. In fact, this momentum is continuing into the second half of the year, as our oil production in the Permian will surpass the 50,000 barrels per day milestone.

We’ve also had success expanding our drilling inventory in the Permian. You might recall, in the first quarter, we doubled our Bone Springs inventory from 350 to 700 locations. Today we’re once again doubling our Bone Springs inventory from 700 to 1,400 locations. This represents more than 1,000 future locations that we’ve added of the past year alone, loosening our oil development inventory in the Permian to nearly 4,000 risked locations.

This low risk development inventory will provide significant light oil growth in the Permian for many years to come. In Canada, our portfolio of world-class thermal oil projects continues to generate industry-leading results, with total production from our Jackfish project averaging 53,000 barrels per day in the quarter.

Upon startup of Jackfish 3 next year, we expect aggregate free cash flow from our 3 Jackfish projects to approach $1 billion annually. Furthermore, our development schedule remains on track to increase net production from our oil sands leases to at least 150,000 barrels per day by the end of the decade.

Also, today we’re announcing some exciting results from our new Woodford oil shale play in the Mississippian trend of north central Oklahoma. To date, we’ve identified 1,000 risked locations in this light oil resource play. Dave will provide more details later in the call.

And finally, our Cana Woodford and Barnett shale positions continue to rank among the top shale plays in North America. Currently, our activity is directed to only the most liquids rich portions of these plays. Aggregate oil and NGLs production growth from these two plays rose nearly 40% year over year in the second quarter. These assets and their midstream infrastructure will produce about a billion dollars of free cash flow in 2013.

In addition to our strong operating results, we benefited from the sharp rise in natural gas and Canadian oil prices. Average second quarter gas price realization nearly doubled compared to the second quarter of 2012, and Canadian oil price realizations improved by more than 50% just from the previous quarter.

We also delivered strong cost discipline in the first six months of 2013. While our production is trending above initial expectations, as I mentioned earlier, capital expenditures and pretax cash costs remain comfortably within our full year guidance ranges.

On the liquidity front, year to date we have moved $2 billion of foreign cash back to the U.S. at an estimated tax rate of approximately 5%. In addition, we’ve moved $500 million to Canada on a tax-free basis to fund our growth projects.

To provide some perspective on the significance of this achievement, recall that after divesting our international assets in 2010 and 2011, we guided toward taxes of about 20%. The lower actual tax rate on the amount repatriated to the U.S. and the tax free transfer to Canada has resulted in an incremental $400 million benefit to Devon shareholders. That’s the equivalent of about $1 per share.

Another positive development is the approval by our board of directors of a plan to form a publicly traded midstream MLP. We expect to file a registration statement with the SEC around the end of the third quarter. As you’re probably aware, pre-offering rules prevent us from providing any additional information at this point, but we believe there’s a great opportunity to unlock the value of our midstream assets for Devon shareholders.

In addition, we’ve recently signed agreements to sell our Bear Paw assets in central Montana, our Thunder Creek midstream assets in Wyoming, and some other minor E&P assets for nearly $300 million. Estimated full year cash flow from these divestiture assets is less than $15 million, and the associated production is essentially all dry gas, averaging around 20 million cubic feet per day.

As you can see, the sale prices for these mature, lower-margin properties are at valuations far superior to that of our current trading multiples, or the multiples we could potentially obtain through an MLP.

These divestitures and our recent midstream MLP announcement are just a couple of examples of our continuing efforts to unlock value in our asset base when we can do so on an accretive basis. Of course, evaluating options to highlight unrecognized value has always been, and continues to be, a priority. However, any action we take must create long term value for our shareholders.

We’ll continue to provide the updates on this front as warranted. At this point, I will turn the call over to Dave Hager for a more detailed review of our quarterly operating highlights. Dave?

Dave Hager

Thanks, John. Good morning everyone. Let’s begin with a quick recap of our second quarter capital expenditures. Exploration and development capital for the second quarter came in at $1.2 billion, bringing our total for the first half of 2013 to $2.7 billion.

Based on our planned activity for the second half of 2013, we’re on track with our full year E&P capital guidance of $4.9 billion to $5.3 billion. As John mentioned, our teams delivered excellent execution in the second quarter, across our entire North American onshore portfolio.

Let’s take a closer look at some of these high points. Starting in the Permian, our production averaged a record 76,000 barrels of oil equivalent per day in the second quarter. Looking specifically at our Permian oil production, it grew 32% year over year.

Light oil now accounts for 60% of our Permian volumes. The execution of our Permian development program through the first half of the year has been outstanding, and we remain on track to drill more than 300 wells this year.

Our Bone Springs horizontal program in the Delaware Basin is a key driver of our Permian oil growth. We currently have 12 operated rigs working in the play. In the second quarter, we brought 29 Bone Springs wells online, with average 30-day IP rates of 675 barrels of oil equivalent per day, of which more than 65% was light oil.

These results are about 15% better than our type curve expectations. Our continued growing success in Eddy and [Lee] counties, combined with our ongoing geological evaluation, has once again allowed us to increase our inventory.

As John mentioned, we are doubling our inventory for the second time this year to 1,400 Bone Springs locations. Given this success, our 2014 program has the potential to double our current year activity to about 200 wells, further accelerating growth of this top tier light oil play.

Shifting to the Midland Basin, we continue to see positive results from the Wolfcamp shale in the southern portion of the Midland Basin. During the second quarter, we spud 34 horizontal Wolfcamp wells and brought 19 online, with initial 30-day production rates as high as 1,000 BOE per day.

Landing and completing these wills in the lower Wolfcamp is yielding positive and consistent results. We believe our fracks in the lower Wolfcamp are extending up through multiple intervals, allowing us to extract additional resource.

In addition, pad drilling and this play is resulting in greater efficiencies and lower costs. In fact, our number of days from spud to rig release has improved nearly 60% since the first quarter of 2012.

Today, we are able to drill our wells in just 11 days, trimming nearly 10% off our budgeted well costs. We have approximately 800 undrilled locations in this light oil resource play, and we’ll be active here for the foreseeable future.

With the recent industry focus on the Wolfcamp, and in light of our 1.3 million net acre position in the Permian Basin, we have fielded multiple questions regarding our total Wolfcamp exposure. Based on our testing across the basin and industry results to date, we have exposure to the Wolfcamp on over a quarter of a million net acres across the Permian.

Beyond our Wolfcamp shale focus in the southern Midland Basin, we have tested other acreage with Wolfcamp potential across the Permian. For instance, in Ector County, where we historically drilled vertical [unintelligible] wells, we have completed two horizontal Wolfcamp wells. Each of these wells had a peak oil rate of about 800 barrels of oil per day.

In addition, we are currently drilling a horizontal Wolfcamp test on our Delaware Basin acreage in Ward County, where industry activity has recently heated up. As we continue to derisk our acreage position throughout the Permian, we believe our total exposure to the Wolfcamp will likely expand significantly. Our massive acreage position in the Permian Basin, coupled with the multiple pay zones of Wolfcamp, provide us with a significant resource upside.

As John mentioned, we’re today unveiling an exciting new opportunity on our Mississippian trend acreage. We have completed 29 wells to date in the Woodford oil shale with very positive results. Second quarter Woodford results were highlighted by 10 wells with initial production averaging 840 BOE per day and 30-day IPs of more than 500 BOE per day.

We are excited about our Woodford potential for several reasons. First, unlike the Mississippi Lime, the Woodford is a shale formation with resource play characteristics. It sits just below the Miss Lime, and can be up to 150 feet thick across portions of our acreage. It is the source rock for much of our Miss production. The Woodford is less geologically complex, and therefore should have a much higher drillability factor and deliver more consistent results than conventional formations.

Second, the type curve emerging from the Woodford oil shale looks very similar to our original type curve in the Miss Lime, with 30-day IPs of about 300 BOE per day and [EURs] of about 350,000 BOE. Furthermore, on a program basis, the drill and complete costs for these wells should run about $3 million each.

Third, initial production is about 80% oil on these Woodford shales. While the EUR is expected to be about one-third gas and about one-third NGLs, this high initial oil content greatly enhances the economics in today’s commodity price environment.

And finally, since Woodford’s geographic footprint overlaps our Miss Lime acreage, the sharing of 3D seismic surface facilities and power and gathering infrastructure will significantly enhance the economics of both plays. On our acreage in the Mississippi and Woodford trend, we have placed about 100 miles of pipeline in service to date, and expect an additional 400 miles in service by year-end.

This critical midstream infrastructure will reduce our operating costs and well backlog, allowing the ramp up in our production. The evaluation of our Woodford potential has also included a successful four-well pilot on 160 spacing. These four wells achieved average 30-day IP rates of roughly 400 BOE per day.

The Woodford’s ease of drilling also allowed us to drill and complete our first 10,000-foot ladder on the trend. The McNeil 6/7H was brought online in the second quarter with an average 30-day IP rate of nearly 700 BOE per day.

Based on our positive results to date, we have recently added 60,000 net acres with Woodford potential to our lease hold position in the area. To date, we have derisked about 100,000 out of roughly 400,000 net acres prospective for Woodford oil shale development. This 100,000 net acres represents about 1,000 risked, undrilled locations.

Combining our Woodford oil shale and Miss Lime results, the second quarter production across the trend averaged 5,000 BOE per day, a 73% increase from the first quarter this year. While we have spud over 200 wells to date, infrastructure limitations, [flaring] restrictions, and wells awaiting completion have limited our production history to 89 operated wells, of which 60 are completed in the Miss Lime.

Our results in the Miss Lime continue to vary, depending on geographic location, reservoir quality, landing zones, and completion techniques, with our best wells far exceeding our type curve. The seismic we have acquired thus far has allowed us to avoid structural geohazards such as faults and [unintelligible] and has allowed us to improve well orientation within the reservoir.

Additional analysis is ongoing to identify correlations between production and the various seismic attributes that can be related back to the geology. As we further refine our [unintelligible] models with the integration of 3D seismic log data and well results, we’re confident we can improve our overall consistency.

Inside our joint venture area, we saw an 80% increase in Woodford 30-day IP rates from our wells drilled with the benefit of seismic. To date, we have acquired 3D seismic over roughly 50% of our acreage inside the joint venture area, and plan to have the remainder of our seismic in this area shot by early next year.

On our acreage to the north, we have a minor amount of seismic already in house, and our acquisition of additional seismic in this area will continue through 2014.

For the remainder of the year, we expect to run 14 operated rigs on our joint venture acreage, where we have the benefit of 3D seismic and one operated rig testing our lease hold to the north. This rig count will keep us on pace to participate in approximately 350 wells for the year.

Given the strength of our Woodford oil shale results, and the fact that Woodford wells secure acreage from the Miss Lime formation as well, we will focus our second half activity on drilling Woodford wells.

This level of activity, combined with the progress we’ve made in building out infrastructure, will allow our net production to approach 15,000 BOE per day by the end of 2013 for the Miss Lime and Woodford oil shale combined.

So, in summary, we are excited about the progress we’re making in the Mississippian Woodford trend, and believe these plays will provide the next leg of large-scale, highly economic oil growth for Devon.

Shifting to our thermal oil projects in northeastern Alberta, second quarter production from our two Jackfish projects averaged roughly 53,000 barrels of oil per day net of royalties. Most importantly, the significant improvement in Canadian oil prices boosted our Jackfish operating margin by nearly 300% quarter over quarter.

Jackfish 1 production averaged 32,000 barrels per day during the quarter, and continued its trend of excellent plant reliability and efficiency. We reached project payout at Jackfish 1 in June, resulting in a step up in royalty rates to the Alberta government going forward. As a result, in the third quarter, we expect Jackfish 1 production, after royalties, to average between 26,000 to 28,000 barrels per day.

To further improve output at our Jackfish project, we’re testing a variety of technologies aimed at enhancing plant and reservoir productivity. While still too early to comment on the results of these pilot programs, industry participants, including Devon, expect that over time, improvements in SAGD technology will lead to step changes in efficiency, ultimately boosting production rates well above our nameplate capacity of 35,000 barrels per day.

At Jackfish 2, second quarter production continued to ramp up, averaging an all-time high of 21,400 barrels per day net of royalties. To further assist the ramp up of this project, an additional well pad has been drilled at Jackfish 2 that is currently being tied in, and remains on schedule for first [steam] later this year.

Looking ahead to the third quarter, we’ll bring the Jackfish 2 plant down for scheduled maintenance beginning in mid-August, and expect the maintenance to take about three weeks. When we restart the plant, it can take up to four weeks to restore production to full capacity. Accordingly, our net third quarter Jackfish 2 production is expected to range an average on the order of 13,000 to 15,000 barrels per day.

At Jackfish 3, we’re ahead of schedule and remain on budget with nearly 70% of the project complete. We now expect first steam in the third quarter of 2014, which is roughly one quarter sooner than we had originally expected.

Also during the quarter, our Rockies oil program in the Powder River basin continued to gain momentum and deliver excellent results. In the second quarter, we brought 7 high-impact oil wells online, targeting the Turner and Parkman formations. Initial 30-day production from these 7 wells averaged 675 BOE per day, of which more than 90% was light oil.

Our Powder River Basin results have driven our overall Rockies oil production up 27% year over year, to 11,000 barrels per day. This recent success in the Powder is attributable to the integration of additional 3D seismic data, coupled with improved completion techniques.

To date, we have identified approximately 600 risked locations across our Powder River Basin acreage, and we expect further good news as we head into the second half of this year and into 2014.

Moving now to the Cana Woodford shale in western Oklahoma, second quarter production averaged 322 million cubic feet equivalent per day, with oil and NGLs comprising nearly 40% of production. This represents an impressive 48% increase in liquids production year over year.

During the second quarter, we spud 28 new horizontal Cana Woodford wells. Because of timing issues related to pad drilling, only three were brought online. We are currently in the process of bringing several new pads online. Expect to see strong third quarter production growth at Cana of roughly 10% sequentially.

In addition, we continue to improve drilling efficiency at Cana. Over the past two years, we’ve managed to reduce drilling days by more than 40%. As a result, we now believe that only 10 operated rigs are required for the second half of the year to complete our 150 well program in 2013.

Our planned expansions at Cana and in the Barnett are now complete and fully operational. Both facilities reached record daily [inlet] volumes and NGL production late in the second quarter. As John mentioned, and it’s worth repeating, our Cana and Barnett assets, combined with our midstream infrastructure, will produce around $1 billion of free cash flow in 2013.

So, in summary, we had an outstanding execution in the second quarter across our entire North American onshore portfolio. With solid production results and a growth of inventory of opportunities, we’re poised to deliver impressive oil and liquids growth in 2013 and beyond.

With that, I’ll turn the call over to Jeff for the financial review and outlook. Jeff?

Jeff Agosta

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

Beginning with production, as John detailed earlier, our record-setting production averaged 698,000 barrels of oil equivalent per day. This was driven by growth in light oil production from the Permian Basin, coupled with the Mississippian and Woodford oil plays in north central Oklahoma. Total second quarter production exceeded the midpoint of our guidance range by nearly 3%, and topped the upper end of our forecasted range by 8,0000 barrels per day.

Looking ahead to the third quarter, we expect to continue to demonstrate year over year growth in our oil volumes, with average daily oil production ranging from 165,000 to 170,000 barrels per day. This implies a year over year growth rate in the high teens.

Driving this strong oil growth in the third quarter is an expected 40-plus percent increase in oil production from our U.S. operations, far surpassing the impact of higher post-payout royalty rates at Jackfish 1 and the planned turnaround at Jackfish 2 that Dave discussed earlier.

Overall, on a BOE basis, after accounting for growth in NGLs and declines in natural gas, we expect production in the third quarter to range between 680,000 and 695,000 BOE per day. Due to the outperformance of our core development assets year to date, we are increasing our full year production target. This is in spite of selling noncore properties.

We now expect our full year 2013 production to range from 250 million to 254 million BOE, an increase in the midpoint of our full year forecast of 4 million barrels. Breaking down our 2013 outlook by product, high margin oil production is the most significant growth driver, where total company oil production remains on track to increase at a rate of 16% to 19% over last year.

NGL growth is also strong, and on pace to increase at a rate in the low teens for the year. Lastly, our operating teams have done a very good job optimizing base production from our natural gas assets. We now expect 2013 natural gas declines of only 7% compared to our 8-10% forecast.

Looking now at our revenues, in the second quarter, significantly improved natural gas and oil price realizations, combined with higher oil production, drove our E&P upstream revenue to $2.2 billion, 37% higher than the year ago quarter.

Oil sales, not including NGLs, once again accounted for more than 50% of our E&P revenue in the quarter. In the second quarter, our regional pricing by product was generally in line with expectations.

One noteworthy exception was the dramatic improvement in Canadian oil realizations. For the second quarter, oil price realizations in Canada came in just above the top end of our guidance range, at 66% of WTI, or roughly $62 per barrel. This represents a 52% increase compared to the first quarter.

This price recovery resulted from higher takeaway capacity provided by improved flow rates on key export pipes, new rail capacity, higher refinery demand, and some delays in production supply growth from industry.

Based on what we have seen so far in July and August, we expect third quarter Canada oil realizations to range from 65% to 75% of WTI. However, supply and demand dynamics for Canadian crude remained tight, so any disruptions in refining or takeaway capacity could negatively impact pricing.

Looking at natural gas, the only notable change to our guidance is a minor adjustment for the recent widening of [ACO] differentials in Canada. We are now projecting third quarter natural gas realizations in Canada to be between 70% to 80% of Henry Hub. For natural gas liquids, we expect our third quarter realizations to range between 26% to 28% of WTI.

Turning now to our midstream business, in addition to our strong upstream performance, our marketing and midstream operations also delivered a solid quarter. Our midstream operating profit came in at $121 million in the second quarter, enhancing our company-wide margins by nearly $2 per BOE.

The improvement in natural gas prices and higher utilization of our fractionation facility at Mont Belvieu were the key performance drivers for the quarter. This resulted in second quarter midstream profit exceeding the top end of our implied guidance range.

With the first six months in hand, we now expect our full year marketing and midstream operating profit to come in between $450 and $500 million, an increase of $25 million from our previous guidance.

Shifting now to expenses, we have continued to do a good job of controlling costs across our entire portfolio. For the first half of 2013, most expenses items have trended toward the bottom end, or even below, our guidance range, including LOE, G&A, taxes other than income, and [BD&A].

For the second quarter, the company’s pretax expenses totaled $1.7 billion. On a unit of production basis, pretax expenses declined 2% from Q1, and increased only 1% year over year. By achieving significant scale and core operating areas, coupled with our consistent focus on cost of management, we are positioned with one of the better cost structures in the industry. This is especially impressive given our shift to oilier projects, which are delivering much higher rates of return but are generally more expensive to operate.

Looking ahead to the third quarter, for those of you who model Devon, we expect the payout at Jackfish 1 and turnaround related expenses at Jackfish 2 to increase our LOE to a range of $9 to $9.50 per BOE. However, our full year guidance remains unchanged.

Before we open the call to Q&A, I will conclude my remarks with a quick review of our financial position. During the second quarter, our cash flow, after adjusting for balance sheet changes and repatriation tax, totaled $1.4 billion, a 31% increase compared to the second quarter of last year. This cash flow allowed us to comfortably fund our capital demands while maintaining excellent financial strength.

Additionally, we reduced our debt by $2 billion using offshore cash balances. We continue to have one of the best liquidity positions in the E&P sector, with cash and short-term investments of $4.2 billion.

Of these cash balances, approximately $3.6 billion resides in subsidiaries outside North America. Depending upon how our 2013 tax position evolves, and once we firm up plans for 2014, there is the potential to bring another sizable amount of cash back to the U.S. at a tax rate in the mid single digits.

In summary, it was a solid quarter for Devon, both operationally and financially. We posted strong oil production growth, we expanded our margins through growth in light oil, higher price realizations, and strong cost controls, and we maintained our solid financial position.

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

Vince White

Operator, we’re ready for the first question.

Question-and-Answer Session

Operator

Our first question in queue comes from the line of Arun Jayaram with Credit Suisse. A line is open for you now.

Arun Jayaram - Credit Suisse

Jeff, kudos on the repatriation. I know that’s been a lot of effort for you and your teams, so congrats on that. My first question is regarding the Woodford play, Dave. Understanding it’s early in this play, but I was wondering if you could just comment a little bit on the consistency of the well results thus far, perhaps the initial rates of return versus the Mississippian program, and bigger picture, what do you think this could do for Devon if you can prove this position out.

David Hager

Well, we’re pretty excited about this opportunity overall, because I think by the nature of being a shale play, and the fact that it is a source rock for the vast majority of the Mississippian play, by the nature of it, shales tend to be more consistent in nature, and so that has led to greater consistency in well results already. And we’re just at the beginning stages of really characterizing the overall play.

So we are seeing more consistent results, there’s obviously some variability. Some of the keys we’re looking for, where we can enhance the permeability through fracturing and you see some variability depending on the thickness of the reservoir, but overall, it is a consistent play that produces strong economic results.

You can see where we’re using, essentially for right now, the same type curve as we’re using for the Mississippian, but it’s going to be a little bit lower well costs. So that’s, obviously, even going to enhance the economics a little bit more.

And as I highlighted, we’re very confident. We derisked 100,000 acres, and we see the potential for up to 400,000 acres of Woodford potential across our 650,000 acre position in the Miss trend. So it’s an exciting play. If it works out to scale, you can do the math, but it can add a lot to our light oil story.

Arun Jayaram - Credit Suisse

And do you have the same water issues that you have in the Miss Lime?

David Hager

No, you don’t have near the water issues you have in the Miss Lime.

Arun Jayaram - Credit Suisse

John, one for you. I wanted to ask you, just around strategic alternatives and potential strategic alternatives beyond the MLP, thoughts on other things such as Canada, thinking about strategic alternatives around Canada to unlock some of the value there of your oil sands position.

John Richels

Without getting into any of the specifics, we’re always looking at ways that we can bring that value forward, and I think our history proves that we’re not afraid of doing that and making bold moves. However, a lot of things that we talk about and reflect on from the outside don’t necessarily add long term value.

And so we’re very conscious about that, and we’re looking at any opportunities available to us. We’ve always said we’re always considering how to bring value forward, and we’re not leaving any stone unturned in that analysis. But we’re only going to do the things that add long term value and not take action simply for action’s sake.

Operator

Next in queue we have Doug Leggate with Bank of America. A line is open for you now.

Doug Leggate - Bank of America Merrill Lynch

Dave, first to you, perhaps. The Mississippi Lime and the Woodford, are we now basically seeing the Woodford as a primary target for your acreage there? And could you talk about what the implications are in terms of development plan, rig count activity, or rather, I guess, well activity, and ultimately how you might change capital allocation associated with this play.

David Hager

We like both of them. I think that’s the key. We like the Woodford and we like the Miss Lime. This is not negative on the Miss Lime, it’s just we have additional potential here in the Woodford. I think that’s really the key. The Woodford is a little bit deeper, and it has some of these additional qualities that we described of being a shale with probably more consistent results, a little bit easier to drill, a little lower well costs, all of which are very positive for that.

And in addition to being deeper, when you drill a Woodford well, you hold all rights above that. And so we’re going to have a tendency to drill more Woodford wells here in the short term to make sure that we get our acreage secured through the Woodford. But ultimately, it’s going to take the rest of this year, I think.

That’s what I’ve been trying to say consistently, that it’s going to take the rest of this year to really get a clear understanding of what the full potential is on both the Woodford and our Miss acreage, but it’s starting to emerge pretty positive, I can tell you, and it looks like we certainly have a strong leg to our next oil growth within Devon. And so I like where we are, bottom line. It’s just nice to have an additional formation such as the Woodford to really bolster that growth.

Doug Leggate - Bank of America Merrill Lynch

I don’t know if you wanted to take my follow up, but it’s related to the carries, clearly the success in the Powder, the Permian, and the Miss. How are you allocating, and what’s the remaining capital carry you have in the two joint ventures that you have with Sumitomo and Sinopec?

Jeff Agosta

We should benefit to the tune of over $1 billion this year and a billion next year.

John Richels

And that’s the two JVs combined.

Jeff Agosta

Yeah, the two combined. But as far as specific to the Rockies and the Miss, that’s got to be upwards of $700 million to $800 million per year.

Operator

Your next question in queue comes from the line of Joseph Allman with JPMorgan. Their line is open for you now.

Joseph Allman - JPMorgan

On the Miss Lime, production increased by about 2,200 barrels per day from the first quarter to the second quarter. And you drilled 44 wells in the second quarter, 34 in the first quarter. These are gross wells. So why is the production not ramping up faster there?

David Hager

It’s important to remember that so far we’ve only brought a total of 64 wells online in the Miss, total of about 90 or so for the combined Miss and Woodford. And so we have currently, as we speak, we’re building out our infrastructure and we’ll be continuing to build out that infrastructure throughout the third and fourth quarter. So as we get the infrastructure built out, as we complete these additional wells, then we’re going to see the ramp up in production even further.

Joseph Allman - JPMorgan

And the Miss Woodford, I think your press release indicated that, so you exited the June quarter at 7,000 barrels a day, you exited the March quarter somewhere in the neighborhood of 3,500 barrels a day, you brought on 36 wells in the second quarter, and you mentioned the 10, that averaged 840 or so BOE per day. So that would imply that the other 26 wells actually had a very low rate. So I was just working the math. I’m just trying to understand what the average of those other 26 was.

David Hager

They’re varied. And it’s important to remember, and I’ll go back to what I said previously, we are still in the testing phase of this. We are landing in various zones within the Miss, and we’re experimenting throughout our acreage. An additional point I need to make is the working interest in a number of these wells. We’re talking about gross wells. And so the working interest in a number of these wells is very low.

So you really can’t do the math I think you’re trying to do, to figure out the rate. But we are seeing a lot of variability right now, and we’ll continue to see that as we evaluate our acreage here throughout the rest of this year. And then we will really be focusing in on what we think are the best parts of the play.

Joseph Allman - JPMorgan

Dave, could you give us the average working interest for the Miss Lime and for the Woodford? I thought it was actually pretty high, with about a 20% royalty.

David Hager

I think it’s averaging about 30% or so.

Joseph Allman - JPMorgan

30% working interest average?

David Hager

Yeah. I might also mention, just to follow up on some of these wells too, we can produce for about 30 days and then we can’t produce them any further, because there are the flaring restrictions we have. So we’ve actually had to shut in some of these wells. So there’s a lot of complicating factors that factor in to why it’s taken a while to ramp. Once we have our facilities in place, that we’re talking about building out here in the second half of the year, that won’t be an issue anymore.

Joseph Allman - JPMorgan

And John, just on the strategic alternatives, as a follow up, from the language it sounds as if that process has slowed down somewhat internally. I think you were looking at options for the midstream business, and you already announced those, but it sounded previously, I think you said everything was on the table. Now it sounds as if that process has slowed down internally. Is that a proper interpretation?

John Richels

I don’t think it’s slowed down. I said everything’s on the table, and everything’s still on the table. If we can see opportunities that create long term value and that make sense and are accretive, then we’ll look at them. But I just wanted to make the point that just undertaking activity for activity’s sake doesn’t make sense unless we think it’s really something that’s going to add some value to the stocks. I wouldn’t say that we’ve changed our view on that.

Operator

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

Brian Singer - Goldman Sachs

Shifting to the Permian, can you talk in more detail about what’s driven the increase in your Bone Springs locations? How much of that is due to incremental Bone Springs zones working, versus you’ve tested a wider acreage, versus spacing, versus EURs, or anything else?

David Hager

Let me give you a little bit of an idea for what is going on here. It’s primarily, as we test additional acreage. That’s the answer. To give you a little bit of color on the details on this, when you look at the logs of this first and second Bone Springs, they are what we like to typically call railroad tracks, which really means we see very little indication of a deflection of the SP curve, or the resistivity curve, which you typically see in productive formations.

And so what this really means is these are pretty fine-grained reservoirs, and so you can’t just look at a log and say for certain that these wells are going to be productive. You have to actually go in and test new areas, and then you find out, oh, it’s working. And so based on that fact, then you step out further, and you step out further, and you say that area’s working too.

So that’s what we’re really doing. We’re stepping out and testing new areas, because it’s just not obvious from the well data that it’s really going to be productive. And what we’re finding is that these areas that just don’t look that impressive by traditional log analysis techniques, when we go out and test them, they’re working really well.

Brian Singer - Goldman Sachs

And my follow up goes back to some of the earlier questions. Is the emergence of this Woodford oil opportunity in the Mississippi Lime area meaningful enough where it reduces your appetite for considering or adding oil resource via acquisition from some new play elsewhere?

David Hager

Well, we’re always going to be very disciplined, I think, if we’re looking at any acquisitions. And so we’re going to, I think, continue to look to see if there are any meaningful, but obviously we haven’t made any deals yet, because we’re being very disciplined from a value standpoint. I think it’s always in our best interest to look, but we’re certainly excited that this adds a lot of strength to our internal oil growth story as well. So I wouldn’t say we’re going to stop looking. We always see if there’s something meaningful out there, but it certainly gives us a lot more confidence on our internal story.

Operator

Next in queue we have [Sue Lin] from Robert W. Baird. A line is open for you now.

[Sue Lin] - Robert W. Baird

A quick clarification question about Woodford oil. Is this part of your Sumitomo JV? And also, what is your planned activity for developing this play in ’13 and ’14? Could you use part of the [drill carry] from the JV?

David Hager

We have 650,000 acres throughout the Mississippian trend. About 150,000 or so of that acreage is within the joint venture, not with Sumitomo, but with Sinopec. And where we’re drilling the bulk of our wells right now is on that acreage that’s within the Sinopec JV, and that has the bulk of the derisked acreage for the Woodford right now. And we see additional prospectivity outside of the joint venture acreage with Sinopec that we’re going to be derisking here throughout the remainder of ’13 and ’14.

So right now, as part of the Sinopec JV, and as part of the overall plan, as part of the 350 wells we talked about that we’ll be drilling overall in the play, and it’s within the budget that we’re working with with Sinopec and the JV.

[Sue Lin] - Robert W. Baird

And then the second question is regarding Powder River Basin. Given that the overall results there seem to be pretty good on Parkman and Turner, and you also have 600 risked locations, I was just wondering is this going to become a core area for you guys? Are there any permitting issues to develop this play here?

David Hager

Well, we’re excited with the results we have. And we’re looking at ways to increase our well activity as we move into 2014. It is BLM land for the most part. Not entirely, but for the most part. There’s a longer permitting process involved in that, so we need to get ahead of the curve as far as permits. We do see the scope for increasing rig activity in 2014. Is it going to grow to the size of the potential that we see in the Miss or the Permian? No, I don’t think so. But is it still going to be a meaningful part of the growth story? Yeah, it can be a significant contributor, I think. Still, it’s probably not going to be of the scale of the Permian and the Miss.

[Sue Lin] - Robert W. Baird

And then my last question is do you have any update for us on Cline, in the Permian?

David Hager

Yeah, on the Cline, we’ve decreased our rig activity right now. We’ve seen a lot of variability on the Cline. And we certainly have our concerns about the Cline, but we’re also getting additional 3D in there. We’re looking at our completion techniques.

For the short term, we’ve decreased down to two rigs in there, both of which are going to be doing what I call mini developments in Sterling County, seeing how low we can get the well costs to have economic developments there. In the meantime, we’re studying the well results we have to date. We’re getting 3D. And as I said, the results have been pretty mixed so far. So we need to do some studying here before we go back out there with a significant program.

Operator

Your next question comes from John Herrlin with Société Générale. Their line is open for you now.

John Herrlin - Société Générale Americas Securities

A couple for Dave. With the Woodford Mississippian trend that you discussed, you said that you had variable thickness in the Woodford Shale. How variable is it aerially, when you look at all this acreage? Or is it relatively uniform?

David Hager

It’s reasonably variable. We have some areas we’re not including in our prospective acreage at all, because it’s not present. And so we’ve seen positive well results, down to as low as 40 to 50 feet of Woodford shale. We’ve seen very good well results, and it’s up to 150 feet thick in other areas. So there is some variability across the play. There’s no question about it. But again, we’ve had positive results down to 40 to 50 feet, and so that’s why we see a lot of it as being prospective.

John Herrlin - Société Générale Americas Securities

When do you think you’ll an HBP mode in terms of capturing all the acreage? This year?

David Hager

We won’t have it all captured this year. It will take on into 2014, particularly to the acreage to the north. The bulk of the acreage within the joint venture area will get HBP this year, but it will be 2014 to really do the acreage to the north.

John Herrlin - Société Générale Americas Securities

Next one from me is on the Permian. Have you hit a stage where you’re in a pad mode yet? You’ve talked about your drilling times improving.

David Hager

Oh yeah, we’re doing pad drilling throughout the Bone Springs, throughout the Wolfcamp shale. We have been for some time. And that’s frankly why some of the ramp up of production has been pretty inconsistent, I guess you’d say.

But to give you an idea, though, just to fortify our production growth in the second half of the year, to give you one example here, in our Wolfcamp shale area, we fracked about 25 wells in July. They’re coming on here in August. We’re going to frack another 25 wells in August. They’ll come on in September.

And so that’s what’s really the cause of the nature of pad drilling that the growth has been a little bit lumpy. But now that we’re getting all these wells drilled, completed, and on production, that’s what gives us the confidence. We’re going to have to kind of ramp up what we’re forecasting for the remainder of 2013.

We’re also pad drilling in Bone Springs. Same issue there.

John Herrlin - Société Générale Americas Securities

Given the results in Bone Springs wells, are you going to increase your EURs there?

David Hager

They’re running at about 15% above the type curve right now. I don’t know, I’ll have to talk to the guys and see if they feel confident in doing it all the way. You understood the issue I talked about before. They’ve got to convince themselves those railroad track looking logs are really going to deliver even more. So we’ll see if they can get that confidence. But we’re getting outstanding results.

Operator

Next in queue we have Rehan Rashid with FBR. Their line is open for you now.

Rehan Rashid - FBR

Just a quick question on Jackfish 2. Once we have the turnaround and the incremental pad in, what should we think about as the run rate?

David Hager

We’re probably going to get an incremental on the order of about 8,000 barrels a day or so from the next pad, so once we’re fully back ramped up, I’d say 30,000 to 31,000 barrels a day, somewhere in that order.

Rehan Rashid - FBR

And this should be by what, middle of next year?

David Hager

Yeah, somewhere around there.

Rehan Rashid - FBR

And just broadly speaking, thoughts around further exploration efforts going on within the enterprise, some broad thoughts on that front? What should we be looking forward to?

David Hager

Well, we’re always out there looking, and we have a lot of ideas internally. Frankly, this has been a year where we had captured a lot of acreage, and we felt it was the year to evaluate that acreage. And given the success that we’re having on that acreage right now, I think it’s an open question as to how much additional acreage we need to add. Because we’ve got a lot of growth that we’re identifying right now from the acreage we’ve already captured. So if we see some that we think are truly outstanding, we may go out and try to capture those, but we’ve got a lot of growth already from what we have captured.

Operator

You last question in queue comes from the line of Charles Meade with Johnson Rice. Their line is open for you now.

Charles Meade - Johnson Rice

I was wondering if we could turn to the Midland Basin Wolfcamp, and those look like some pretty good results that you have there, but I’m curious, I know that at least one of those two Ector wells you did in 2012 was a relatively short lateral. I want to say it was around 3,000 feet. And so I wondered if you could add some detail, first on what your lateral lengths were on these wells that you reported with this quarter. And second, if you could give a breakdown of the 250,000 net acres that you have prospective for the Wolfcamp, how much of that is Delaware and how much of that is Midland.

David Hager

On the lateral lengths for the wells in Ector County, we’re currently drilling those about 5,000 foot laterals. Not quite as long as the ones we were doing in the southern Midland Basin. The breakdown of the Wolfcamp shale acreage that we have, it’s about 140,000 acres or so that we think is prospective in the Delaware Basin. Then we have about 65,000 acres or so, I think, perspective down in the southern Midland Basin. And then the rest of it is up in Ector County, and then some other smaller, scattered acreage.

Vince White

John, do you have any closing remarks?

John Richels

Just want to summarize. Our annual production is going to be at the top end of our guidance, with our U.S. light oil production up 36% year over year. Really importantly, too, year to date cash costs are at the bottom end of the guidance, and our capital expenditures remain comfortably within our original guidance. We’re going to continue to expand our high margin light oil drilling inventory in the Permian, and we’re very excited about the new Woodford oil shale play that David’s discussed a lot today.

So was we move forward, we’re going to continue to be disciplined with our capital, we’re going to continue to preserve our financial flexibility, we’re going to continue to pursue our top strategic objective of maintaining long term growth and cash flow per debt-adjusted share. So thank you very much for joining us today.

And with that, I guess we’re done.

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