Vincent White - Senior Vice President of Investor Relations David Hager - Executive Vice President of Exploration & Production Jeffrey Agosta - Chief Financial Officer and Executive Vice President John Richels - Chief Executive Officer, President and Director

Brian Singer - Goldman Sachs Group Inc. Scott Hanold - RBC Capital Markets, LLC David Tameron - Wells Fargo Securities, LLC Scott Wilmoth - Simmons & Company International Mark Gilman - The Benchmark Company, LLC Douglas Leggate - BofA Merrill Lynch Rehan Rashid - FBR Capital Markets & Co.

Thank you, operator, and good morning, everyone. Welcome to Devon's second quarter 2011 earnings call and webcast.

As usual, I'll begin today's call with a few preliminary items and then turn the call over to our President and CEO, John Richels for his perspective. Following John's remarks, Dave Hager, our Executive Vice President of Exploration and Production will provide the operations update and then Jeff Agosta, our Chief Financial Officer will finish up with a review of our financial results.

We'll conclude with a Q&A period and we'll hold the call to about an hour. A replay will be available later today through a link on our homepage, that's devonenergy.com.

During the call today, we're going to provide some minor updates to our 2011 forecast based on the actual results for the first half of the year and our outlook for the remainder of the year. In addition to the updates that we're going to give in today's call, we'll file an 8-K later today as is our usual practice that will provide details of our updated 2011 estimates.

These updates can be accessed using the Guidance link on the Investor Relations section of Devon's website. Please note that all references in today's call to our plans, forecasts, expectations, estimates and so on are considered forward-looking statements under U.S.

securities law. And while we strive to give you the very best estimates possible, many factors could cause our actual results to differ from our estimates.

We'd encourage you to review the discussion of risk factors and uncertainties provided in the Form 8-K that we are filing today. Also on today's call, we will refer to certain non-GAAP performance measures.

When we do that, we are required to provide certain related disclosures and those disclosures are also available on the Devon website. With those items out of the way, I'll turn the call over to President and CEO, John Richels.

Thank you, Vince, and good morning, everyone. Let me begin by stating the obvious.

Devon's second quarter of 2011 was an excellent one. Our North American onshore production reached an all-time record, averaging 660,000 equivalent barrels per day.

That's a 5% increase over the first quarter, continued focus on efficiency and cost control, mitigated industry inflation and the impact of a stronger Canadian dollar. In fact, our pretax cash costs per equivalent barrel were essentially flat compared to the previous quarter and the year-ago quarter.

With production above our guidance, higher realized commodity prices and effective cost management, our second quarter adjusted earnings climbed 10% over the prior year quarter to $1.71 per diluted share and that exceeded the first call mean by $0.17. Cash flow before balance sheet changes reached $1.6 billion or $3.81 per diluted share surpassing the street mean estimate by $0.48.

Net earnings including the gain on the sale of Brazil totaled a whopping $2.7 billion for the second quarter or $6.48 per diluted share. And during the second quarter, we repurchased 7.1 million shares for $584 million.

To date, we have spent $2.6 billion of the $3.5 billion current authorization to repurchase 35.1 million shares. This represents almost 8% of our outstanding shares and those shares were acquired at an average price of roughly $74 per share.

We remain on track to complete that repurchase program by the end of the year. In May, we closed our $3.2 billion sale of our Brazilian assets which essentially completes the strategic repositioning of Devon to a company focused entirely onshore in North America.

Our total pretax divestiture proceeds exceeded $10 billion, with after-tax proceeds estimated to $8 billion. Currently, we have more than $6.5 billion of cash and short-term investments outside the U.S.

that we have not repatriated. However, it's important to note that our after-tax estimate of proceeds assumes full payment of the taxes triggered by repatriation of most of those funds under current U.S.

tax law. If a more favorable tax situation develops for the repatriation of these funds, or if we redeploy the proceeds in Canada, we will have up to $900 million of upside.

Until we have better visibility into potential repatriation tax legislation and determine the optimal long-term capital allocation between the U.S. and Canada, our divestiture proceeds will remain outside the U.S.

Devon has emerged from the repositioning in a truly enviable position. We have a deep inventory of low-risk drilling locations, including years of high margin oil and liquids-rich development in our cornerstone project areas.

These include the Barnett, the Cana, and our steam-assisted gravity drainage projects in Canada. We are drilling our most economic wells ever in the liquid-rich portions of the Barnett.

Our first mover position has provided us with the largest and best acreage position. Furthermore, our low entry and royalty cost enhanced the economic returns across our inventory of thousands of undrilled Barnett locations.

In the liquids-rich Cana, we're taking advantage of opportunities to increase our working interest and are continuing to delineate our condensate-rich acreage to the northwest. We could continue for years at our current pace of development without any additional inventory.

However, in order to bring forward the value embedded in our existing acreage positions, we're pursuing a wide range of exploration opportunities across North America. In the Permian and Western Canadian sedimentary basins, for example, we're accelerating oil and liquids-rich exploration drilling.

Given the recent advances in drilling and completions technology and the stacked pay nature of these basins, we're pursuing more than 20 oil and liquids-rich plays that have emerged in these 2 basins alone. Our inventory represents more than 3 billion oil equivalent barrels of net unrisked resource across our more than 5 million net perspective acres.

These substantial positions provide Devon with thousands of potential locations, representing many years of additional growth. We're also moving forward with the testing of our new venture plays.

These include the Tuscaloosa, the Niobrara, the Mississippi Lime in Oklahoma, the Ohio Utica, and the A1 Carbonate and Utica in Michigan. We've been successful with our strategy of acquiring sizable positions in these oil and liquids-rich plays, where, for the most part, competition had not yet driven up prices.

Instead of leasing large blocks of trend acreage and then figuring out where the play works best, we've taken a more targeted approach. Similar to our approach in the Cana play, we've attempted to identify the best parts of the plays and specifically focused our acreage acquisitions in those areas.

Utilizing this approach, we've secured 1.1 million net acres at a very reasonable costs in what we believe to be highly economic parts of these 5 plays. While each of these plays has risk, it's likely that several will turn out to be highly economic large scale development plays.

The second half of this year is shaping up to be an exciting time for Devon, with the initial drilling results anticipated from a wide range of exploration opportunities. In summary, the repositioned company has all the attributes necessary to deliver highly competitive per share growth.

We're generating excellent, full cycle returns. We have superior financial strength and we have a deep inventory of economic, low-risk development projects and promising exploration projects in emerging plays and new ventures.

So with that overview, I will turn the call over to Dave Hager for a review of our quarterly operating highlights. Dave?

Thanks, John. Good morning, everyone.

We continue to see outstanding results from our 2011 E&P capital program. Our key development plays, including the Barnett, the Cana and Jackfish are all performing very well.

We also remain very active in evaluating and de-risking the upside potential in our various emerging and new venture plays. With more than 90% of our 2011 E&P capital allocated towards oil and liquids-rich projects and with the solid results we have seen so far this year, we are well on our way to deliver liquids growth in the high teens in 2011.

So let's take a look at some of the highlights for the quarter. Starting with our oil -- our thermal oil projects in Eastern Alberta, Jackfish continues to deliver industry-leading performance.

During the second quarter, Jackfish 1 production averaged 31,000 barrels per day net of royalties. At Jackfish 2, we began injecting steam in the second quarter.

All 4 pads are currently in the circulation phase of the process. As some of you may have recall from our recent SAGD school, this is the initial stage where steam is injected into both the injector and producer wells to begin warming the reservoir.

Later this month, 3 of the pads will move into the partial SAGD phase and production will continue to ramp up. We exited the second quarter producing about 1,000 barrels per day net of royalties at Jackfish 2.

At Pike, with data from nearly 400 wells and some 60 square miles of seismic, our SAGD team has begun engineering work on a 105,000-barrel per day facility for Pike 1. This would be essentially 3 Jackfish-sized facilities from a single plant site.

You might recall we completed the resource evaluation for 2 of the 3 projects with last winter's stratigraphic drilling. Planning efforts are already underway for our 2011, 2012 winter drilling and seismic programs and we'll focus on defining the third 35,000-barrel per day project in the Pike 1 complex.

Ultimately, we believe that Pike can support 4 or 5 Jackfish-sized projects. And when combined with Jackfish, we expect to grow Devon's net thermal oil production to between 150,000 and 175,000 barrels per day by 2020.

Moving now to the Permian basin, we currently have 19 operated rigs pursuing targets in numerous play types across our roughly 1 million net acre position. Our second quarter production from the Permian increased 17% over the second quarter of 2010 to 49,000 oil equivalent barrels per day.

Oil and natural gas liquids accounted for 75% of the quarter's production. In the Permian in our Wolfberry light oil play, we currently have 5 operated rigs running, as we continue the evaluation and development of our 160,000 net acres.

Through the second quarter, we had drilled approximately 50 of our planned 135 well program for this year. We recently initiated a 4-well 20-acre infill pilot program and we'll be testing the application of horizontal drilling in certain areas as well.

We have significant running room in this high return light oil play, with more than 850 net risked locations remaining. On our roughly 200,000 net acres in the Bone Springs oil play, we currently have 5 operated rigs running.

We continue to have great results from our horizontal programs, on both the New Mexico and Texas sides of the play. In the second quarter, we completed 8 wells in the second Bone Springs interval in New Mexico, with 30-day average IP rates of 665 barrels of oil equivalent per day.

This included one exceptionally strong well, the Diamond [ph] 1H that was brought online with an average 30-day IP rate of more than 1,100 barrels of oil equivalent per day. Our Bone Springs well cost in New Mexico are running about $5 million per well, with EURs averaging 400,000 barrels equivalent.

On the Texas side in the Bone Springs play, we completed our third well targeting the third Bone Springs interval. The 100% Devon-owned Talladega 65 2H was brought online recently.

After 15 days of production, this well has averaged 1,000 barrels of oil equivalent per day. Although our Texas Bone Springs production history is limited to just a few wells, we are encouraged with the shallow declines we have seen to this point.

With average EURs exceeding 600,000 barrels equivalent, and with well cost running about $7 million, these wells offer outstanding returns. We've planned out a third rig in the Texas side of the play later this year, bringing our total number of rigs working in the Bone Springs up to 6.

Also in the Permian, the Delaware is another conventional oil information that we are targeting with horizontal drilling. We completed 3 wells in the second quarter, including the Laguna Salada 6H that came online with a 30-day IP rate of more than 800 oil equivalent barrels per day.

We now have 3 operated rigs drilling Delaware horizontal wells. Elsewhere in the Permian basin, we are targeting 2 operated rigs in the Avalon Shale play.

Our activity is now focused on our 65,000 net acres in the eastern portion of the play where condensate yields are higher. We currently have 3 wells in various stages of drilling or completion and should have those results for you next quarter.

And finally, in the Permian basin, we have assembled approximately 65,000 net acres in the southern end of the Midland Basin and the Wolfcamp Shale oil play. We are currently running 2 operated rigs with our first 3 wells in the play in various stages of drilling or completion.

We hope to have results for you next quarter. This is a hot play in the industry, and with the positive indications we've seen to date, we now plan to drill 8 Wolfcamp Shale exploration wells in 2011.

In addition to the Midland Basin acreage, we have about 200,000 net acres in the Delaware Basin that is perspective for the Wolfcamp Shale. We're currently drilling our first well to test this formation's potential in the Delaware Basin.

Moving north to the Texas panhandle and the Granite Wash play, we continue to see solid results from our Cherokee and Granite Wash 8 [ph] wells. We are running 5 operated rigs here and brought 8 operated Granite Wash wells online during the second quarter.

The 30-day IP rates from these wells averaged over 2,000 barrels of oil equivalent per day, including 200 barrels of oil and 730 barrels of natural gas liquids per day. Moving now to the Cana Woodford Shale in Western Oklahoma.

As everyone is well aware by now, our Cana gas processing plant was damaged by a tornado on May 24. It's worth noting that we have both property and business interruption insurance that Jeff will cover in more detail later.

Work is underway to repair the damage and we expect the plant to be fully repaired and operational during the fourth quarter. We are confident of our year-end exit rate target for Cana of 275 million cubic feet equivalent per day, net to Devon's interest.

In spite of the planned interruption, our second quarter net Cana production averaged 17% over the first quarter to a record 189 million cubic feet equivalent per day, including nearly 9,000 barrels per day of liquids. To keep pace with our Cana Woodford growth and capture additional value from the liquids-rich portions in the field, we plan to begin the first expansion to our Cana gas processing plant later this year.

The facility's initial processing capacity of 200 million cubic feet per day will be expanded to 350 million a day and will be capable of extracting up to 27,000 barrels of NGLs per day. The $125 million expansion is expected to be operational in the fourth quarter of 2012.

Shifting to the Barnett Shale field in North Texas. This field continues to be a significant and highly economic resource for us.

Our 2011 program has yielded the best wells we have ever drilled in the Barnett. We have seen average EURs increase to 3.2 Bcf equivalent per day.

We ran 13 operated rigs in the Barnett for most of the second quarter. Subsequent to June 30, we dropped one rig, bringing our operated rig count back to 12, where we expect to keep it for the remainder of the year.

In the second quarter, we brought 114 Barnett wells online, with average 30-day IP rates of approximately 3.4 million cubic feet equivalent per day, including an average 125 barrels of liquids per day. In the second quarter, our net production reached a record 1.28 Bcf equivalent per day, that is 1,280,000,000 cubic feet equivalent per day including 46,000 barrels of per day liquids.

This represents a 5% sequential quarter increase and a 13% increase over the second quarter of last year. With the high liquids yield we are seeing from our Barnett drilling combined with our outlook for gas and NGL product spreads, we recently made the decision to expand our Bridgeport gas processing plant for the seventh time.

The 140-million-a-day expansion will provide an additional 11,000 barrels per day of NGL production capacity. The $160 million expansion is expected to be operational in the first quarter of 2013.

Upon completion, the Bridgeport facility will have an inlet capacity of 790 million cubic feet per day, with an NGL production capacity of 65,000 barrels per day, making it one of the largest gas processing facilities in the lower 48. On the exploration front, as John indicated, we are continuing to actively evaluate the oil and liquids potential on acreage within our portfolio that spans numerous play types across multiple basins in the U.S.

and Canada. This includes several new ventures areas in the U.S.

where we have assembled 1.1 million net acres. And in Niobrara, we have approximately 200,000 net acres in the Powder River Basin and 100,000 net acres in northern part of the DJ Basin.

This is a very active industry play right now, with about 30 rigs working. Many of the industry wells drilled to date were drilled without the benefit of 3D data, making it difficult to target, identify and land in the appropriate zones.

Our initial focus in the DJ Basin will be to utilize 3D to improve upon the lack of consistency demonstrated to date in this play by the industry. We are currently drilling our first wells in both basins.

We plan to drill or participate in 6 Niobrara wells in the Powder and 4 in the DJ basin in 2011. In the Mississippi and oil play located in North Central Oklahoma, we have secured over 200,000 net acres.

This is a play originally established by vertical production years ago, but is now being pursued with horizontal drilling. We drilled our first vertical well to gather data in the second quarter, and we're currently drilling our first horizontal well.

In total, we plan to drill or participate in 12 to 15 wells in 2011. There has been a lot of discussion lately of the Ohio Utica Shale.

And as most of you know, Devon was an early mover. We've established 110,000 net acres in what we believe in the heart of the oil window.

The primary risk to a shale play is of course the ability to move fluid through a very tight reservoir. However, we have now analyzed the core from our first Utica well and are highly encouraged by the positive permeability indications seen in our first well.

Based on these early results, we believe the oil window could offer some of the best economics in the play. We plan to drill 3 additional Ohio Utica wells this year.

Just to the north is our 300,000 net acre position in the Michigan Basin is prospective for both the Utica Shale, as well as the A1 Carbonate. As you may know, this has historically been a prolific basin.

We are particularly excited about the potential of the A1 Carbonate which was the source rock for the Niagaran Reef play in Michigan. We drilled our first 2 vertical core wells and are currently evaluating the data.

And finally, in the Tuscaloosa Shale play located along the Louisiana and Mississippi border, we recently completed drilling, coring and logging operations on our first well, the Lane 64-1. This is a vertical well that we drilled to obtain data.

The rig has now moved up depth to the Beech Grove 68 1H (sic) [ 68H-1 ] where we plan to gather additional core and log data before drilling the lateral and completing it as our first horizontal in the Tuscaloosa. Another exploration play that has recently caught the Street's attention is the Smackover Brown Dense oil play located in North Louisiana.

We have about 40,000 net acres perspective in the play and expect to spot our first horizontal well in this play next month. As I mentioned, we also have a significant exploration effort underway in Canada, targeting the deep basin where we have Cardium and lower Cretaceous drilling programs underway, as well as Cardium program in the Ferrier Area of our Central Alberta and our Viking program in Saskatchewan.

Although wet weather has delayed a portion of our Canadian exploration program, we still expect to complete our 2011 program. However, at our Viking light oil play in Saskatchewan, we did complete 2 wells in the second quarter, one of which IP-ed at 90 barrels of oil per day.

We expect this play to be economic, with well costs in the $1 million to $1.2 million per well range, IPs of approximately 40 barrels per day and EURs of 50,000 barrels. While these results are encouraging, we're still in the early stages of evaluating the potential on our 900,000 net acre position.

If successful, we could have more than 1,000 Viking drilling locations. In summary, all of our key development projects are delivering excellent results, supporting our production growth targets.

Growth is being driven by liquids growth in the high teens. In addition, we are entering a very exciting time on the exploration front as we get our first wells down in a variety of different plays.

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

Thank you, Dave, and good morning, everyone. Before we move into the financial review for the quarter, I would like to remind everyone my comments will be focused on results from continuing operations.

In other words, our North American onshore business. With the close of Brazil, this will be the last quarter that contains significant activity within discontinued operations.

For those of you interested in a more detailed review of our discontinued ops, we have provided supplemental tables in our news release. For today's call, I will limit my comments to those items that require additional commentary or were outside of our forecasted guidance range.

The first item I will cover is our production for the quarter. In the second quarter of 2011, our reported production totaled 60.1 million oil equivalent barrels or 660,000 Boe per day.

This result set a quarterly production record for our North American onshore operations and represents a robust 5% growth rate over the first quarter and a greater than 6% increase over the year-ago quarter. Additionally, our production exceeded the midpoint of our guidance range by roughly 10,000 barrels per day, in spite of deferring production from Cana due to tornado damage at our plant there.

Our outperformance was driven by strong results from our core properties. Also, a gas royalty adjustment in Canada boosted reported second quarter production by about 7,000 barrels per day.

Looking specifically at the liquids side of our business, our oil and natural gas liquids production averaged 220,000 barrels per day for the quarter, a 12% increase over the year-ago period. The most noteworthy year-over-year growth came in the U.S., led by strong growth from the Barnett, Cana and Permian basin, we increased our second quarter U.S.

oil and NGL production by 22% over the second quarter of last year. Looking ahead, we expect downtime at our Cana processing facility to curtail third quarter production by roughly 10,000 Boe per day.

In spite of this temporary curtailment, we still expect third quarter production to range between 655,000 and 665,000 barrels per day. Our sequential quarter production growth for the third quarter will be masked by the tornado impacted Cana volumes and the 7,000 Boe per day royalty adjustment in Canada that we reported in the second quarter.

For the full year, we are now raising the bottom end of our production forecast by 2 million barrels to a range of 238 million to 240 million barrels. When compared to 2010, the midpoint of our updated guidance range implies a top-line production growth rate of more than 7% for our North American onshore properties.

This growth will be achieved in spite of deferring approximately 2.5 million barrels of production due to severe weather, principally the damage to the Cana plant. Turning to hedges.

In the second quarter, cash settlements from oil and gas hedges totaled $59 million. These settlements boosted our company-wide average price by about $1 per Boe in the quarter.

Since our last conference call, we have continued to bolster our natural gas hedge position. In the second half of this year, we now have a combination of swap and collar contracts covering approximately 980 million cubic feet per day at a weighted average protected price of $5.28 per Mcf.

We have also more than doubled our natural gas hedge position for next year. For the full year of 2012, we now have hedges covering 850 million cubic feet per day, with a weighted average protected price just under $5 per Mcf.

However, 60% of these hedged volumes are done using collars. Therefore, we still maintain upside on these volumes should natural gas pricing improve.

We will post an updated hedging schedule in our 8-K filing and on our website that provides a detailed view of our 2011 and '12 hedge positions. Turning now to our Midstream business, In addition to our strong upstream performance, Devon's marketing and midstream operations also delivered outstanding results.

Operating profit for the second quarter came in at $148 million, well above the high end of our implied guidance range. Strong NGL prices and increased throughput drove the increase.

Looking ahead, we expect the downtime at our Cana processing facility to reduce our third quarter marketing and midstream operating profit to a range of $120 million to $140 million. However, for the full year, in spite of the setback at Cana, we now expect our operating profit to come in between $515 million and $545 million.

This represents an increase of $20 million from our previous guidance. It is worth noting, as Dave mentioned, that we are well-insured for both the property damage and business interruption that has occurred at our Cana facility.

Our policy deductibles are $2.5 million per property damage and a 30-day wait for business interruption. After the 30-day waiting period, our business interruption coverage pays for the loss of production, not only from the wells that were producing at the time of the storm, but also for the ramp up of volumes that would be occurring from the wells that we are drilling.

Consequently, our risk management has mitigated most of the financial impact of this incident. Looking now at our expenses.

In the second quarter, most expense items came in the bottom half of our guidance range. Our focus on controlling costs, combined with our high-graded asset base has helped offset both industry inflation and the headwinds of the strengthening Canadian dollar.

Looking ahead to the remainder of the year, we anticipate continued upward pressure on costs. However, we are confident that our scale and key operating regions and consistent focus on cost management will allow us to mitigate much of the impact of inflation.

Looking at our income taxes, Devon's reported second quarter income tax from continuing operations came in at $1.2 billion. This implies an 87% tax rate on pretax income from continuing ops.

The most significant item that influenced our quarterly tax rate was a $744 million charge related to the assumed repatriation of foreign earnings to the U.S. This is essentially a non-cash charge which results from a required accounting exercise that assumes that we will repatriate a substantial portion of these funds under current U.S.

tax law. However, as John mentioned earlier in the call, we have not repatriated these funds and they currently reside outside the U.S.

In any case, after backing out the assumed repatriation charge and the impact of other nonrecurring items, you'd get an adjusted tax rate of 32% which is right in line with our guidance. Going to the bottom line, Devon's solid second quarter performance and the profitable sale of our assets in Brazil translated into record GAAP earnings of $2.7 billion.

After backing out the nonrecurring items, our adjusted earnings totaled $726 million or $1.71 per diluted share. Our cash flows before balance sheet changes totaled $1.6 billion.

As John mentioned earlier, this was a solid beat on both earnings per share and cash flow. Before we go to the Q&A, I would like to provide a quick update on our financial position.

In the second quarter, Devon's cash inflows totaled $4.8 billion. After funding all capital demands for the quarter, repurchasing $584 million of common stock and paying out $72 million in dividends, our cash and short-term investments increased by over $3 billion during the quarter, reaching a total of $6.7 billion.

As a result, our net debt declined to just $1.2 billion and our net debt to cap ratio declined to just 5%. Following the end of the quarter in the month of July, we issued $2.25 billion of senior notes through a combination of 5-, 10- and 30-year offerings.

This allowed us to take advantage of today's attractive market conditions to fund our upcoming $1.75 billion of debt maturing in September, as well as reduce our outstanding short-term borrowings. In summary, we are excited about Devon's future and believe that we are well-positioned to compete effectively.

Our financial position provides us with significant strength. As importantly, our assets are performing very well.

We remain focused on maximizing our operating margins, exercising capital discipline and optimizing growth for debt-adjusted share. At this point, I will turn the call back over to Vince for the Q&A.

Vince?

On this session today, we have, not just the speakers, but our Executive Chairman, Larry Nichols is with us and as usual we'll ask each participant to limit his or her questions to one initial inquiry and one follow-up. Operator, we're ready for the first question.

I guess I'll direct this one to John. John, you've got an awful lot of options on the table, in terms of your -- what is a pretty exciting exploration program going forward.

Assuming that at least several of those work, what would your capital priority be in terms of future capital expenditure, in terms of obviously you're still maintaining a lot of capital in the Barnett, particular, how would you look to flex the capital program, would the capital program go up or would you reprioritize within the portfolio? And I have a quick follow up, please.

Well, Doug, I mean, certainly, with our financial position where it is, we've got the ability to pursue a lot of opportunities. I think what we'll have to do is we're really excited about these new opportunities that we're pursuing.

We'll have to see when we have more data, how they stack up one against another. Over a longer period of time having -- that's a high-class problem to have, or a high-grade problem to have, if we have that many opportunities, but we'll just have to see exactly what the economics look like.

We are, as you mentioned, we're getting great economics and greater returns out of our Barnett Shale program. Even at $4.50 gas this year, that play is going to cash flow somewhere at $1.8 billion on $1 billion investment of capital and we're getting great results out of Cana and some of our other development programs.

We'll just have to see how they all stack up and how much we want to invest to bring the value forward on these new opportunities.

Great. My follow-up is actually kind of a related question.

It's maybe one for David, but the rig count, could you give us some ideas as to how you see the trajectory, let's say, through the balance of this year. I guess, included in the question, the drilling efficiencies that you're seeing from the existing rig count, is that improving?

Because it looks like we're seeing some significant change in the context of your very production numbers.

Yes, Doug, I would say that for the rest of this year, we see our rig count staying essentially flat and we're still finalizing our plans, as we look forward to 2012. So I don't want to predate our process, internal process, here too much, but probably we're going to be looking at somewhat of a flat program next year also compared to this year.

And on the efficiency side, yes, we're continuing to see increased efficiencies throughout our program and we're continuing to see it in the Barnett, we're seeing it in Cana. Obviously that's part of the reason we actually had a capital increase here, we announced a few weeks ago, because we're drilling so many more wells and we're keeping the rigs for the full year, then we're getting more wells drilled than we originally anticipated.

But that is the good news, and we're taking those learnings on how to do that throughout our entire program including our new ventures area.

Looking at the Utica Shale. Obviously a lot of cheddar on that and you guys indicated you saw some pretty encouraging things as you looked at your vertical core.

Can you just, in generally, just talk about what specifically you see within that core that gets you excited and how you kind of compare some of the attributes versus some of the other liquids-rich plays you are involved in?

Well, I don't want to get too much into the specific analysis of it. But I can say, obviously, that we have a lot of experience in looking at a lot of shale plays throughout the U.S.

and we understand what we need, in terms of what type of permeability is necessarily, especially in light of the fact that we are primarily in the oil window and it is a normally pressured oil window. It's not overpressured.

So, obviously, you need a little bit higher perm in order to move the oil through, but I think we understand that and we know where the permeability is and we're encouraged. And the ultimate test, obviously, is to drill some horizontal wells out there and we don't have any horizontal wells, but we think we have a pretty good understanding from our vast numbers of horizontal wells we drilled throughout the North America that we understand the relationship pretty well and we're optimistic.

And then turning to the Permian, obviously, it seem like you continue to step up activity and you're seeing some good things there. What is your rig counts specifically in that area?

And how many rigs do you think you're going to be operating in the Permian as you look into 2012?

We are currently running 19 rigs in the Permian and I can break those net rig count down for you in a little bit more detail. We have 5 rigs -- I think, I pretty well did it in the prepared remarks, but there are 5 in the Bone Springs, 5 in the Wolfberry, 3 in the Delaware horizontal program, 2 in the Avalon, 2 in the new Wolfcamp Shale play that I described in the Southern Midland Basin where we've assembled 65,000 acres and a couple of others that are drilling conventional oil plays within the basin.

We see that program staying pretty flat going into next year, but we're very excited with the results that we have achieved with that. We'll have to see -- if we do have continued success, we might move the rig count up a little bit or limit it a little bit by the infrastructure availability out there and just as we need to mature the play.

So it's possible, it might move up a little bit as we move into next year, I wouldn't see -- look for a doubling or anything like though of the rig count. But it's probably perhaps a small increase in the rig count moving into 2012.

Just a couple of quick things. David, you may have done this, but frankly you're just going too fast for me to possibly keep up.

But I didn't hear you talk about any kind of recent drilling results in the Avalon?

Yes, when -- I didn't go through that in a lot of detail, Mark. I would say that what we're finding in the Avalon, so far, is that we are seeing strong gas rates in the Avalon.

We are seeing, as we move from west to east in the Avalon, that we get -- that it becomes more liquids-rich and we haven't drilled as many wells in the central and eastern part of the play as we started our program in the Western. So right now we are moving into the part of the play that is more liquids-rich in the most economic part of the play and we really need to get some completions on that part of the play before I can talk in any more specifics.

Okay, Dave. My follow-up relates to what you think in terms of the liquids content of the program going forward into Barnett and the Cana?

I mean, obviously the more recent wells are yielding a much higher liquids content than you've seen in your base production in the areas. Do you have any thoughts on what that looks like going forward?

Well, we talked about plant expansions in both those areas. And so, obviously, that gives you an idea that we have a deep inventory of liquids-rich opportunities in both those areas.

In the Barnett, we probably have about 2,000 locations in the liquids-rich part of the play and we're getting outstanding economics in the liquids-rich part of the play, both in the Barnett and in Cana. And so we see -- and frankly in Cana, we have not drilled as much in the core of the Cana as we have around the core.

That's the only area in the company where we have had to drill some wells in order to get it held by production. We focused part of our program on that versus infilling in the core which is very liquids-rich.

So we see tremendous opportunities there also to infill the core. You've seeing how our downspacing projects have worked well, so we anticipate that we're going to have a strong liquids growth and that's part of the reason why we're expanding the plant in Cana as well.

If I could just follow up, what I'm trying to get a handle on is, at the margin, do you think the liquids rates that you're seeing in both those plays can be sustained at what we're seeing right now? Can they go higher?

Are they likely to back off?

Mark, this is Vince. I'll give you a couple of observations.

About 22% of the BTUs coming out of the Barnett right now are liquids. We are focusing our activity on the liquids-rich portions of the play.

So if the relative economics continue to favor the liquids-rich portion, we would expect the percentage of our BTUs in the Barnett that are liquids to go up. Following the de-risking of the Cana, if the current -- the market conditions are similar to what they are now, that highly favor liquids-rich drilling over dry portions, then we would expect to increase the liquids yield, as a percentage of the total BTU stream out of the Cana just like in the Barnett.

And Mark, we talked from time-to-time about the fact that we were not going to increase our processing capacity in those areas for a short term because we want to make sure that we efficiently allocate that capital. And the fact that we're expanding our processing capacity in both of those plays shows you where we think that liquids volumes are going here in the next while.

Following up on some of those Permian questions. With regards to the various Delaware Basin horizontal zones, you seemed to be getting good results out of the second Bone Spring in New Mexico, the third Bone Spring in Texas and you just discussed the Avalon here.

Can you provide a bit more color on the first Bone Spring in New Mexico and then whether you see any of the 3 Bone Spring zones, along with the Avalon, commercially overlapping on your acreage?

Well the first Bone Springs is also perspective -- is perspective a little bit further to the north, basically as you move from north to south, you go from the prospectivity being in the first Bone Springs to the second Bone Springs. And then once you cross the New Mexico-Texas line there then the third Bone Springs is primary perspective on the Texas side.

But there is some overlap though between the first and second Bone Springs. And so yes the first Bone Springs is perspective as well on the New Mexico side.

It's not -- I don't want to give you the idea that it's strictly a resource play type though. It's the first and second Bone Springs are more channel sands, so you have to make sure that you stay in the channels.

And then as you move down into Texas, those channels essentially splay out and they become like a deepwater depositional system and when you go off the shelf edge and that's where you get the really high rates in the third Bone Springs, once those channels splay out on the Texas side.

As a follow-up, when we look at the cash currently outside the U.S., can we talk a little bit more about potential capital allocation, how does your ability to repatriate that cash into the U.S. versus move it towards Canada impact your willingness to expand new venture acreage position versus buyback additional stock versus make larger acquisitions?

There's a lot of questions there, Brian, but, let me take a crack at that. I mean, right now obviously, as Jeff mentioned, we're still trying to sort out the income tax rules to see whether we could bring it back to the U.S.

What it does do is to the extent that we allocate some of those funds in Canada, we've got a lot of projects there as well. We've got a very ambitious program for our thermal heavy oil.

I'm excited about the growth there. It allow us to invest some funds at a -- that will create a higher return because they're not as opposed to bringing them back and paying the tax.

So that's something that we're trying to work out, trying to figure out the optimal capital allocation between the U.S. and Canada.

And with regard to share buybacks, unfortunately, I thought at one time it would be clever if we bought our shares back through our Canadian subsidiary, but the folks at the IRS have all that figured out as well and we can't do that with any advantage. But in terms of buying back our stock, we're going to do what we always have.

And looking ahead, determine what's going to create the best debt adjusted share returns and best [ph] metrics for our shareholders and allocate that capital appropriately between our E&P opportunities and buying back stock. And as you know, we haven't been shy about that.

We bought back about 20% of our stock in the last 6 or 7 years. So we'll have to see all of that sorts out over the next while.

We're certainly hopeful that we're seeing, at least, some modicum of acceptance or positive indication of maybe being able to bring some of those funds back. Jeff, do you have any other comment?

Yes, I would just add, Brian, we're not inhibited in bringing that cash back. We're just really wanting to see how any potential changes to U.S.

tax law may play out over the coming months to see if we can bring that back at an enhanced tax rate.

You guys mentioned infrastructure constraints in the Permian. Can you give us more details on that and what your outlook is for the remainder of the year in 2012, in terms of Permian infrastructure?

Well, we see the infrastructure continue to expand throughout next year and the following year. There is particularly on the New Mexico side, there is really a lack of natural gas processing capability from the region and so you really can't ramp up the liquids-rich play significantly in the area where you're talking about the Avalon potential of New Mexico, so that is a constraint.

The rest of the areas, I would not characterize really as being infrastructure constrained. I'd say it's more, it's just how quickly we can mature those plays and feel comfortable that we've properly de-risked the plays.

Okay, and then just following up on your 2012 rig count assumption, you said probably flattish for next year. Is that assuming a ramp-up in some emerging plays or is that if you have success, could that go higher?

Well it potentially could go higher with success, yes. And so we're committed, obviously, to balance though to stay -- to balance our opportunities against our -- stay in very strong financially also, and so we've got to put all of that together.

And if we have significant success in these plays, we'd have to see, as John mentioned, just how we handle that situation, but there are a lot of options for us to bring value forward in the event that we have success in these plays through partnering relationships, et cetera. So there's a lot of different ways to solve that problem if that does occur.

A couple of questions. Canadian -- I guess I got two questions, Canadian exploration can you talk -- you talked a little bit about the Viking, the Cardium and some of the Cretaceous stuff that you're doing, but can you talk -- give us a little more color what you're most excited about, maybe horizontal potential, are you going horizontal?

Can you just give us more detail on that up in Canada?

Yes, we're excited about all of them. And frankly we're excited about the fact that we have 4 million acres in the Western Canadian Sedimentary Basin and we have done very little exploitation of those for liquids-rich and oil-type opportunities.

So we see a very large number of opportunities that could emerge from there. The 3 that we've been traditionally highlighting so far this year are the Viking light oil potential that I mentioned, where we're going to have 1,000 to 2,000 locations across our acreage, 9,000 acres in Saskatchewan.

The Cardium light oil play that -- where we have drilled a some wells in the Ferrier Area. But more importantly up in the Deep Basin, we think we have at least 80,000 prospective acres for the Cardium.

And then also in the Deep Basin, we're going to be start drilling this fall what we call our Vertizontal Program where we are going to be taking wells that would go actually horizontal in the deepest zone, which will be the Cardomin [ph] and then also complete simultaneously in some of the vertical zones in some of the stacked pay areas. But in addition to that, we're drilling a number of different wells and a number of different play types up there that, with success, all of which could amount -- could be significant and I've got a whole list here of ones we could go through, but it's not worth going through all the details on all of them, but there's just a large number of opportunities, but we're just at the front end of evaluating all these.

Okay, all right, let me burn my follow-up on something else. John, you kind of alluded to it, but didn't directly answer the question or didn't answer the question I was looking for.

What's the plans for 2012 share buyback?

We haven't made those plans yet, David. As we get into -- as we talked before, what we're trying -- what we're doing is -- there's always -- there's kind of a level of activity we have to have in the company, right?

Which is just to maintain our organization capacity, our service sector capacity to meet our throughput commitments, our processing facility optimization, all of those things. After that, we want to be very thoughtful and dispassionate, frankly, in our views as to whether we're better off allocating funds to share buybacks or capital programs, and we want to allocate it to those areas that are going to create the best returns and the best debt adjusted share returns for our shareholders.

Now as we get further through the year and we haven't obviously finalized or even come close to our 2012 capital budget, there are a lot of moving parts. And our view as to whether we ought to be buying our stock back rather than investing in our E&P programs is dependent on our stock price, on our view of commodity prices for the future, on our view of costs in the future and how that influences our per debt adjusted share metrics.

So we'll have to -- we'll have to see how we -- what we do in 2012. 2011, we were really happy to be able to do a lot of each.

And as Vince has mentioned before, we sold roughly 8% to 10% of the company for 23% of the enterprise value and significantly shrunk our balance sheet and that's creating some very good returns and good per-share accretion for our shareholders. So we'll just have to see, I can't give you a more definite answer than that because we're still in the early stages of determining what 2012 looks like.

Just a quick one, can we compare the Powder and the DJ Niobrara? Is it going to the same kind of variability you think to where we could...

It's a little too early to say on that. I think that as you are in the DJ Niobrara, you probably have a little bit more chalk in those, which would give you greater confidence that it's going to be brittle and will frac easier, so we think that's certainly a positive.

There haven't -- the activity is slowly moving north in the Powder River Basin and there have been some positive results in the Powder River Basin, but it's still a little too early to know -- just the frac-ability of the reservoir is probably the biggest risk that exists up in the Powder River Basin, and as we and others drill more, we'll learn more about that. But we think overall it will work, but that's probably the biggest risk that sits out there.

It's just how much -- when you have less chalk, you have other material in the Niobrara that will allow it to frac to the degree that it does in the DJ Basin.

Got it. And a follow-up, if I may.

Just the new ventures activity as you pick up acreage all across the country, is there a common geological theme that you're focusing on that you can share?

Well, I'd say a common theme is that we want to get in, not so much geologically, but we want to get in -- we want to make money with these plays, is probably the most common theme, and so we get in early in these plays. We get very reasonable lease turns.

We get very low -- we get low royalties. We get positions with scales so that if we have success, we can apply economies of scale and get the well cost down and we can create a lot of values.

But our organization has the capability to evaluate a lot of different plays, so I don't think I'd say, I'd generalize as much on the geology as -- we're focused on making money.

Okay, it's the top of the hour. We'd like to thank everybody for participating in today's call and remind you that the Investor Relations staff will be around for the remainder of the day for any follow-up or for those that we didn't have a chance to get to in the question queue.

Thanks for your participation.