Devon Energy Corporation (DVN) Q3 2012 Earnings Report, Transcript and Summary

Welcome to Devon Energy Third Quarter Earnings Conference Call. [Operator Instructions] This call is being recorded. At this time, I would like to turn the conference over to Mr. Vince White, Senior Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you, operator, and good morning, everybody. Welcome to today's third quarter 2012 earnings call and webcast. Today's call will follow our usual format. After I make a few preliminary comments, I'll turn the call over to our President and CEO, John Richels. He will provide the overview of the third quarter and his thoughts on the upcoming quarter and year ahead; then Dave Hager, the Head of Exploration and Production, will provide the operations update; and following that, our CFO, Jeff Agosta, will finish up with a review of our financial results and an updated outlook. After Jeff's discussion, we'll have a Q&A session. Our Executive Chairman, Larry Nichols; as well as Darryl Smette, the Head of Marketing, Midstream and Supply Chain, are both with us today to help out in the Q&A. And as usual, we'll keep the call to about an hour. A replay of this call will be available later today on our website. During the call today, we're going to provide an update of some of our forward-looking estimates based on the actual results that we've seen over the first 9 months of the year and our revised outlook for the fourth quarter. In addition to these updates, we will file an 8-K later today containing the details of the updated fourth quarter estimates. To access this guidance, you can just click on the guidance link found in the Investor Relations section of our website. Please note that all references today to our plans, forecast, expectations and future estimates are forward-looking statements under U.S. securities law. And while we always try to give you the very best information possible, there are many factors that could cause our actual results to differ from those estimates. You can find a discussion of risk factors related to our estimates in our Form 10-K. Also, in today's call, we'll refer to certain non-GAAP performance measures. When we use these measures, we're required to provide related disclosures which are available on Devon's website. During the third quarter, we recorded a non-cash property impairment charge of $1.1 billion or about $700 million after-tax. This charge resulted primarily from the lower natural gas prices over the last 12 months. And under full cost accounting rules, the carrying cost of our oil and gas properties is subject to a quarterly ceiling test. I just want to clarify that this write-down was simply an accounting exercise and is not reflective of the fair value of our assets. It does not relate to any specific reserves. It also has no impact on our cash flow or cash balances nor our credit agreements. It's worth noting that this charge is not unique to Devon. Beginning last quarter, that is the second quarter of 2012 and extending into the third quarter, several companies in our peer group have taken impairment charges. With that out of the way, I'll turn the call over to John Richels.

Thank you, Vince, and good morning, everyone. Thanks for joining us this morning. First of all, the organic conversion of our asset portfolio to a higher oil waiting remains on track as evidenced by our continued growth in oil production. We continue to invest the majority of our capital in high-margin North American oil projects. Over time, these high rate of return projects, combined with the greater capital efficiency that's provided by our joint venture structures, should result in superior growth of cash flow per share adjusted for debt. Devon's third quarter performance reflects our continuing progress towards this goal, so let me give you a few highlights of the quarter. Driven by better-than-expected price realizations and low overall unit cost, adjusted earnings per share and cash flow per share for the quarter came in well above the mean Street estimates. Company-wide oil production increased 14% over the third quarter of 2011, and this was achieved in spite of scheduled plant maintenance at our Jackfish 1 Oil Sands project. Jackfish 1 maintenance reduced third quarter oil production by about 10,000 barrels per day. Without the impact of the Jackfish turnaround, oil production would have increased more than 20% over the year ago quarter. Our U.S. oil production, which is our highest margin product, grew 26% in the third quarter, and that was driven largely by our success in the Permian Basin. With the expansion of our Gulf Coast Fractionators facility now complete, our midstream business resumed full operations in the third quarter, and our marketing midstream operating profit reached $109 million, and that's right at the top end of our guidance range. Devon also delivered strong performance from a cost containment perspective. Third quarter 2012 pretax cash cost per BOE declined 2% from the second quarter, and our recent decision to close our Houston office and consolidate those operations into our Oklahoma City headquarters will result in additional savings beginning in 2013. In September, we closed our $1.4 billion joint venture arrangement with Sumitomo in the Midland Basin, Wolfcamp and Cline Shale plays. With the closing of this transaction, Devon has now successfully closed 2 exploration joint ventures during 2012 with a total value approaching $4 billion. We generated $1.4 billion of operating cash flow in the third quarter. And when combined with the upfront proceeds from our Sumitomo joint venture and other minor asset sales, total cash inflows reached about $1.9 billion. On the liquidity front, we exited the month of September with $7.5 billion of cash and short-term investments and a net debt-to-cap ratio of 15%, thereby continuing to maintain one of the strongest balance sheets in the peer group. And lastly, with the recent rise in natural gas prices, we have meaningfully added to our 2013 natural gas hedge position. In the third quarter, we did, however, have some setbacks. Our third quarter top line production came in at 678,000 BOE per day or about 1% below the midpoint of our guidance. The shortfall was driven by 2 key factors: First, we had lower volumes from our liquids-rich gas projects than in our initial plan; and second, the ramp-up of production at our Jackfish 2 project has been slower than expected. Dave and Jeff will cover both of these items in more detail later in the call. Looking ahead to 2013, we are currently in the process of working through our capital budgeting process. Directionally speaking, we expect next year's E&P capital spend to be significantly less than 2012, driven by a sharp reduction in spending on leasehold capture and exploration. Even with this reduced level of spending, we expect to maintain an oil-focused drilling program with activity levels similar to those of 2012. We expect to see significantly higher drill-bit activity on our joint venture projects. You'll recall there our partners will fund roughly 80% of total well costs. And in 2013, we will continue to aggressively pursue our Permian Basin opportunities. We'll move our oil sands developments forward in Canada, and we will accelerate activity in our emerging Mississippi line play. As we've done in the past, we will finalize our 2013 budget in the coming months and provide detailed guidance during our fourth quarter call and through a subsequent 8-K filing. As we sort through various alternatives for capital deployment, we remain unwavering in our commitment to our top strategic objective, that is, to maintain -- to maximize growth in cash flow per share adjusted per debt. We're confident that the disciplined pursuit of this objective will allow us to deliver significant value as we move forward. In addition, we believe the long-term growth potential of Devon's oil projects, both light sweet crude in the U.S. and heavy oil in Canada, married with an option on natural gas provided by our world-class gas resource plays, differentiates us from the other companies in our sector. So at this point, I'll turn the call over to Dave Hager. Dave?

Thanks, John. Good morning, everyone. Before we get to the highlights of the quarter, I'll begin with a quick recap of 2012 capital expenditures for our exploration and development activities. E&P spending was $1.7 billion for the third quarter, bringing E&P capital through the first 9 months to $5.3 billion. We expect fourth quarter expenditures for exploration and development to be approximately $1.7 billion, pushing us outside the top end of our full year guidance range by roughly $400 million. Roughly half of this increase is a result of capturing more acreage than previously budgeted in Permian, Mississippian and other oil-focused plays. The balance is related to accelerated activity to evaluate and build out infrastructure on our Mississippian acreages outside of the Sinopec JV. Of course, the $1.3 billion in cash that we've received this year as a result of the JV is not netted against capital expenditures for reporting purposes. Moving now to area-by-area highlights, starting in the Permian, our Permian production averaged a record 65,100 barrels of oil equivalent per day in the third quarter, up 30% over the third quarter of 2011. Looking specifically at our Permian oil production, it grew by 35% over the same period, with light oil now accounting for nearly 60% of our total Permian volumes. We continue to be very active in the basin with 20 operated rigs focused on drilling higher return oil opportunities. Our Bone Spring horizontal program in New Mexico continues to yield excellent results. We have 6 rigs currently running in the play. In the third quarter, we brought 18 Bone Spring wells online, with average 30-day IP rates of 565 barrels of oil equivalent per day, 80% of which is light oil. We've been very active in the Bone Springs over the past couple of years drilling more than 130 wells, including some 90 wells this year. However, in spite of this high level of activity, we have not burned through our drilling inventory. Through our ongoing geological evaluation, we have been successfully regenerating our opportunities. We have identified 300 remaining risked Bone Springs locations in the second and third Bone Springs formations. In addition, we are currently testing the first Bone Spring potential on a portion of our New Mexico acreage, and the early results were encouraging. If successful, this could add material to our existing multiyear drilling inventory. Also in the Permian, we continue to have very good results from our 2 rig program targeting the Delaware oil formation. We brought 7 wells online during the third quarter, with an average 30-day IP rate of just over 600 barrels of oil equivalent per day. Roughly 80% of this production stream from these wells are also light oil. To date, we have identified approximately 200 additional risk locations in the Delaware, and we are optimistic that with additional geological work, we can expand our drilling inventory here as well. In the Wolfcamp Shale in the southern Midland Basin, we brought 5 Wolfcamp horizontal wells online in the third quarter. These wells had average 30-day IP rates of 556 barrels of oil equivalent per day, of which, over 80% is liquids and almost 60% is light oil. These IPs are right in line with our type well profile for this play. Our productions from the Wolfcamp Shale has almost quadrupled since the beginning of the year. And we're continuing to drive down well cost in this play and expect our next few wells to be in the $6.5 million range. The continued improvements we're seeing from both a productivity and cost perspective give us confidence we can achieve consistent economic results in the play. We have almost 100,000 net acres perspective for the Wolfcamp and the Sumitomo JV. In the Cline Shale area on the Eastern flank of the Midland basin, we have been steadily ramping up drilling activity. I'll remind you that this acreage is prospective for the Wolfcamp and the Mississippian formations in addition to the Cline Shale. We had 3 operated rigs running at the end of the third quarter and just last week, added a fourth rig. We tied in our second Cline horizontal well during the third quarter and saw encouraging results. The Virginia City Cole C 1H located in Sterling County has had a 30-day IP rate of 450 barrels of oil equivalent per day. Our third Cline horizontal well is just starting to flow back, and we have 5 additional wells in various stages of completion, including one well targeting the Mississippian formation. Consequently, we should have a lot more detail for you in the next quarter. The 556,000 net acres in this area within the Sumitomo joint venture represents thousands of risk locations. Shifting now to our thermal oil projects in North Eastern Alberta. Third quarter aggregate production from our 2 Jackfish projects averaged 44,300 barrels of oil per day, net of royalties, in the third quarter. As we indicated in our last quarter call, Jackfish 1 was taken down for 3 weeks during the third quarter for scheduled maintenance. Plant operations were restored on September 11. However, it takes a few weeks to fully restore the steam chambers and ramp production back up. Accordingly, fourth quarter production at Jackfish 1 is expected to average about 23,000 barrels per day, net of royalties. Looking ahead to 2013, we now expect to reach payout at Jackfish 1 at some point in the first quarter. The operational success of the project combined with high oil prices have resulted in a fairly short time to payout. With the WTI price in the mid- to upper-80s, we'd expect our post payout royalty at Jackfish 1 to be between 20% and 25% versus our current 5% to 6% pre-payout rate. In spite of the significant step-up in the royalty rate, we expect Jackfish 1 production to average between 25,000 and 27,000 barrels per day in 2013, net of royalties. At Jackfish 2, third quarter production increased 7% over the second quarter, averaging 19,800 barrels per day, net of royalties. However, it has now become apparent that the maturation of steam chambers on a couple of our initial well pads is progressing at a slower rate than originally expected. This is a result of some localized interbedded shales and sill stones delaying the development of steam chambers. Although these obstacles have slowed steam chamber development, the chambers will eventually develop, enabling the reserves to be fully recovered. However, in order to accelerate production and utilization of our plant, we are currently drilling the first of 2 additional well pads and expect to begin steaming the first pad late next year. Until then, we'd expect our production from Jackfish 2 to average between 20,000 and 25,000 barrels per day, net of royalties, except during the routine plant scheduled -- routine plant turnaround scheduled for 2013. It's important to understand that even among the highest oil quality oil sands reservoirs like we have on our Jackfish and Pike acreage, it is not uncommon to see some variability within the reservoir. We encountered similar variability at Jackfish 1, but the strength of our earliest wells offset the potential timing issues that can result from reservoir variability. In hindsight, additional wells at the outset of our Jackfish 2 project would have bridged the timing gap and ensure full utilization of plant capacity within the expected time frame. The delayed ramp-up should impact the total project rate of return of Jackfish 2 by a little less than 3%, with a project return based on current prices of roughly 20%. We will incorporate this lesson into the Jackfish 3 and Pike projects. The cost of adding a couple of spare well pads on this project at start-up is a relatively minor capital acceleration in the scope of the overall project and can help ensure that normal variations in well pad performance do not have the potential to significantly impact production ramp-up. Jackfish 3 construction continues to progress well, with a project approximately 45% completed at the end of the third quarter, putting us on track for a start-up around year-end 2014. At Pike, we continue to work with our partner on the evaluation of construction execution strategies with the goal of providing greater cost and schedule uncertainty. Given the pressure on labor in the region, we are currently exploring a more modularized approach in use of Jackfish. This would allow more of the labor to be done in a manufacturing facilities rather than the field and should show -- should result in significant efficiencies. We expect to finalize our development plan by the middle of next year. We plan to drill 35 stratigraphic wells and shoot approximately 55 square miles of seismic during the 2012, 2013 winter season. With the majority of the Pike 1 resource already identified, the data obtained from this year's winter drilling program will substantially complete the evaluation of the first phase of development for Pike. Engineering work is ongoing, and we hope to obtain regulatory approval by the end of 2013. As a reminder, the Pike 1 development project will have gross production capacity of 105 barrels of oil per day, and Devon operates Pike with a 50% working interest. Moving now to the Cana Woodford Shale in Western Oklahoma. We brought 25 operated wells online in the third quarter at Cana, with average 30-day IP rates of 6.5 million cubic feet equivalent per day, including 483 barrels of liquids per day. These wells have average EURs of 9.3 billion cubic feet equivalent, making them some of the best wells ever drilled at Cana. These wells are much stronger than the tight curve we presented at our Analyst Day last April, which called for an IP of 4.4 million cubic feet equivalent per day and EURs of 8.3 Bcf equivalent. In contrast, the Cana wells we drilled during the second half of last year have underperformed our expectations. Because we are in a regional drought, we use smaller fracs to reduce water consumption. Industry data at that time suggested that we would not sacrifice much in a way of rates or recoveries. However, as we have brought these wells on and observed their performance through the first 3 quarters of this year, we were seeing that the smaller fracs significantly impacted well performance. We now believe the wells drilled in the second half of 2011 have EURs that are only about half of the Cana core type curve. In early 2012, we added surface water facilities that secured plenty of water for our Cana completion operations, mitigating the impact of the drought. This allowed us to return to our previous stimulation program. And while Devon's third quarter 2012 production from Cana increased 42% over the third quarter of 2011, our volumes at Cana are currently running about 8,700 barrels equivalent per day below our previous expectations, attributable to the performance of the wells drilled in the last half of 2011 and to some variation from plan and the timing of bringing on well pads. Even though it is short of our original forecast, we still expect sequential growth in the fourth quarter Cana production of more than 10%. We began the third quarter with 15 operated rigs at Cana. After initially moving 3 rigs to the Mississippian oil play in Oklahoma earlier in the third quarter, we later made the decision to move 5 additional rigs to the Miss and ended the quarter with 7 rigs at Cana. The Cana rigs were a logical choice for redeployment in the Miss because of close geographic proximity of the 2 plays makes for a relatively easy and inexpensive move. However, given the strong performance of the 2012 drilling program, it is likely we'll add additional rigs to Cana in 2013. Shifting to the Barnett Shale in North Texas in the third quarter, we had 10 operated rigs running in the liquids-rich core and the oil window. We tied in 67 wells, driving our average third quarter net production to 1.4 Bcf equivalent per day, up 8% from the year ago quarter. Moving west to the Texas Panhandle and the Granite Wash area, we continue to see solid results. We brought 7 operated wells online during the third quarter. To date, our drilling is focused primarily on the Granite Wash A and B sands and the Cherokee. However, in the third quarter, we drilled our first operated well in the Hogshooter formation with excellent results. The Brown 8-7H located in Wheeler County had a 30-day average IP rate of nearly 2,200 BOE per day, including 1,688 barrels of light oil and 170 barrels of NGLs. Subsequent to quarter end, we tied in our second Hogshooter well. The Lott, 3-2H has been online for just 14 days and has averaged 4,400 BOE per day, including 3,200 barrels of oil per day. We currently have 2 additional Hogshooter wells in various stages of drilling and completion. Further geoscience work and drilling is needed to fully assess our potential, but our preliminary work suggest up to 100 additional locations. With this kind of productivity and a drilling complete cost of roughly $8 million, the returns on these wells are very strong. We plan to move a fourth rig to the Granite Wash later this year. Our Granite Wash production has grown from about 6,700 BOE per day in the first quarter of 2010 to 18,500 BOE per day in the third quarter this year. With the impact of our Hogshooter program, we would expect further volume growth going forward. On the exploration front, we continue to see encouraging results in the Ferrier corridor of Alberta where Devon has roughly 240,000 net acres perspective for Cardium oil, the liquids-rich glauconite and other lower Cretaceous zones. Given the strong economics from the more than 24 horizontal wells we drilled to date, we are currently evaluating a potential development plan that would include the construction of a gas processing facility. We expect to make a decision as a part of our 2013 capital budgeting process, and we'll keep you updated as we move forward. In the U.S., we continue to move forward with the evaluation of a number of exploration plays, including those within the Sinopec JV. As we began to gain clarity on which of these plays will effectively compete for capital within our portfolio, we will determine how to monetize the positions we don't plan to pursue. Keep in mind that JV has allowed Devon to look at these plays with very little impact from a net capital perspective. Let me provide a brief update on the current status. Looking first at the Rockies oil exploration, we've had encouraging results from wells testing several different formations, including an oil well we just completed in the Powder River Basin that has been on production for 7 days, averaging 1,100 barrels of oil per day. A very encouraging result. In the Ohio Utica, as we indicated last quarter, the results from the wells in the western portion of the oil window had been disappointing. We have since shifted our drilling efforts further to the east and expect to have 3 or 4 wells down on this for eastern acreage by year-end. In the Tuscaloosa Marine Shale, we tied in our third and fourth wells in the northern portion of our acreage position during the third quarter. The Murphy 63H located in West Louisiana parish had an average 30-day IP rate of 260 barrels of oil per day from a 4,700 foot lateral. Roughly 40 miles to the east in Tangipahoa Parish, the Thomas 38H was brought online and had a 30-day IP rate of 470 barrels of oil per day from a 4,900 foot lateral. We would need to see improvements in both cost and recoveries to make this an attractive play going forward. Finally, in the Mississippian oil play located in North Central Oklahoma, we currently have 13 operated rigs running. Devon has 545,000 net acres in the play. We significantly ramped up our drilling activity in the third quarter, drilling both saltwater disposal wells to prepare for full-scale development and a number of producers. We currently have 20 operated Mississippian producers awaiting completion. So we expect to have a more robust update for you next quarter. However, we did tie in the Bontrager 1-28H in the third quarter with an average 30-day IP rate of 545 BOE per day, including 480 barrels of oil per day. These results continue to support a type curve with a 30-day IP of roughly 300 BOE per day and an EUR of 300,000 to 400,000 BOE, at a cost of $3 million to $3.5 million each per well. Our 545,000 net acres represents many years of drilling inventory for us. We currently estimate that the risked resource potential net to Devon at over 800 million of oil equivalent. In summary, our 2012 capital program continues to drive strong oil production growth, while simultaneously evaluating a wide range of exploration prospects. With that, I'll turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

Thanks, Dave. Good morning, everyone. This morning, I will take you through a brief review of our third quarter results and the impact on our outlook for the upcoming quarter. The first item I will cover is production. Our third quarter production totaled 62.4 million oil equivalent barrels or 678,000 BOE per day. This represents a 3% increase compared to the same period last year. The oil side of our business delivered most of our year-over-year growth, outpacing the decline in natural gas. In total, oil production increased 14% over the third quarter of 2011 to an average of 143,000 barrels per day, once again strong year-over-year growth in our Permian and Jackfish project areas drove the performance. Looking ahead to the fourth quarter, we expect to continue growing our oil with average daily production approaching 150,000 barrels per day. This implies 2012 oil production growth of almost 20% over last year. We expect to achieve this in spite of the impact from the Jackfish 1 turnaround of about 10,000 barrels per day and the delays in the ramp-up of Jackfish 2 that Dave discussed. On the gas side, downtime at third-party facilities during the fourth quarter, the impact of the 2011 Cana drilling program that Dave discussed and the underperformance of a Cotton Valley Taylor development program that we are no longer pursuing, will result in a decline in our fourth quarter natural gas production of about 3% compared to third quarter. Net-net, we now expect company-wide production of oil, gas and NGLs to be essentially flat with this year's third quarter at 670,000 to 680,000 BOE per day. Now for a brief review of our revenues. In the third quarter, production growth along with improved Canadian heavy oil realizations and higher natural gas prices drove our upstream revenue up by 7% over the prior quarter to $1.7 billion. In aggregate, oil sales, not including NGLs, once again accounted for more than 50% of our total upstream revenue in the quarter, while revenue from methane continues to be minimal at just 4% of total sales. Looking ahead to the fourth quarter, we expect regional price differentials to be generally in line with our previous guidance, with a couple of notable exceptions. Better pipeline availability and increased demand for heavier crudes during the first half of the fourth quarter resulted in much lower differentials. We are back in a season of heavy refinery maintenance and downtime and the supply of heavy crude is up, so differentials have temporarily widened again. However, the average fourth quarter realizations will still be better than previously forecasted. We now expect our fourth quarter oil price realizations in Canada to range between 64% and 74% of WTI. For natural gas liquids, high inventory levels at Mont Belvieu, along with continued growth in NGL supplies, continue to put pressure on NGL realizations. We expect fourth quarter realizations to range from 29% to 34% of WTI. Looking briefly at the impact of our hedges. In the third quarter, our hedge position delivered cash settlements of $243 million. In total, these cash settlements enhanced our average realized prices by $3.89 per BOE, an uplift of 14% to company-wide realizations. For the fourth quarter, we have approximately 90% of our forecasted oil production locked in with a weighted average floor price of $96 per barrel. We also have more than 80% of our expected gas production in Q4 hedged at a protected price of $3.64. John mentioned earlier that the recent upward movement in natural gas prices has provided us with a good opportunity to add attractive hedges for next year. For the full year of 2013, we now have roughly 1 billion cubic feet per day of natural gas hedged with both swaps and costless collars. Of this amount, 518 million cubic feet per day is swapped at an average price of $4.19 per Mcf. The remainder is collared at a ceiling price of $4.33 per Mcf and a floor of $3.53. These gas hedges, coupled with our 2013 oil hedges of 76,000 barrels per day at a protected price of nearly $97 per barrel, provide a good foundation on the hedging front for next year. For more details on our hedging positions, please visit the guidance section of our website that Vince referenced earlier. Turning now to our midstream business. Our marketing and midstream unit generated $109 million of operating profit in the third quarter, enhancing our company-wide margins by $1.75 per BOE. Improved gas prices and cost containment efforts help us reach the top end of our guidance range. These solid results were also aided by the resumption of our operations at our Gulf Coast Fractionators facility in Mont Belvieu, following the completion of a recent plant expansion. Looking ahead to the fourth quarter, we expect our midstream operating profit to range between $90 million and $110 million. Shifting now to expenses. As John said earlier, we continue to do a good job of controlling costs. In the third quarter, expenses in several categories were lower than guidance, most notably LOE and G&A. In aggregate, our pretax cost were $14.04 per BOE, about 2% lower than last quarter. This is an especially positive result considering our continued focus on higher margin, the higher cost of oil production and the negative volume impact on the quarter of the Jackfish turnaround. Our scale in core operating regions and consistent focus on cost management allow us to maintain one of the most competitive cost structures in the industry. Moving now to DD&A expense. Our third quarter DD&A expense was $716 million or $11.46 per BOE, right in line with our expectations. Looking forward, given the weakness of natural gas and NGL prices over the past 12 months, there's a chance for an additional but much smaller impairment charge in the fourth quarter. Should this occur, our fourth quarter DD&A rate would not be impacted. For Q4, we now anticipate our DD&A rate to be between $11.30 and $11.50 per BOE. Cutting to the bottom line. As John mentioned earlier, our non-GAAP earnings, which exclude the asset impairment charge and other items that analyst generally do not attempt to forecast were $0.88 per share, $0.19 higher than the Street's mean estimate. Stronger-than-expected price realizations and lower pretax cash costs were the key drivers of the beat. This level of earnings translated into cash flow per share of $3.01, exceeding the Street's expectations by 7%. Before we open the call to Q&A, I will conclude my remarks with a quick review of our financial position. During the third quarter, our operating cash flow approached $1.4 billion. When you combine that with more than $500 million of proceeds from closing the Sumitomo joint venture and other minor asset sales, our cash inflows for the quarter totaled $1.9 billion. This cash allowed us to comfortably fund a robust capital program while maintaining excellent financial strength. As mentioned earlier, we exited September with a net debt-to-adjusted cap ratio of only 15%, and one of the best liquidity positions in the E&P sector with cash and short-term investments of $7.5 billion. While Devon clearly possesses a great deal of financial strength and flexibility, we are fully committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength and optimizing our per share growth and cash flow adjusted for debt. So with that, I will turn the call back over to Vince for the Q&A. Vince?

Operator, we're ready for the first question. Operator?

[Operator Instructions] And the first question comes from the line of Doug Leggate from Bank of America Merrill Lynch.

I wonder if I could ask you, I don't know if you're going to be able to provide a lot of detail on this, but the rig allocation that you have currently, I wonder if you could maybe give us a quick summary as to where you are now. But more importantly, given John's comments about spending being substantially lower next year, I wonder if you could give us an early stear as to how you expect activity to be allocated across your plays next year. Obviously, I'm anticipating it's 100% on liquids again, given the new acreage areas and the success you've had. I'm just trying to get an idea as to how that's going to shake out. And I have got a follow-up, please.

Sure, Doug. This is Dave Hager. I'll give you an idea for where the rigs are right now and where they'll be next year. It will be just a summary comment before I go into all the numbers. I wouldn't expect a great deal of difference, but we are going to continue to ramp up the Permian activity next year. We're going to be very active in the Mississippian next year. So we have 2 very high-quality oil plays there, and we're going to -- you will see some increases there. But everything else I think would be fairly static with where we are. But to complete the picture for where we are right now, we currently have 20 rigs working in the Permian. Of those 20, about 9 are working in the Bone Springs and Delaware plays, about 5 in the Wolfcamp Shale and the Cline Shale combined, 3 in the Wolfberry and 3 in the Central Basin Platform. We have 10 rigs working in the Barnett, 7 rigs working in Cana, and we'll probably ramp that back up a little bit more next year also. Mississippian, as we said, we have 13 rigs working there. We have a total of 7 rigs working in what we call our southern division, and that includes the work we're currently finishing up in Ohio and Michigan, 3 doing Canadian exploration, 3 doing Granite Wash, and we had mentioned, we're going to be going up to 4 rigs there with the success of our Hogshooter program. 4 in the Rockies, 1 in Lloydminster and 1 other doing conventional work in Canada, for a total of 69 rigs.

And Doug, it's John. Just let me put a little bit more color around what Dave said and reflect back to what I was saying earlier. We are going to be cutting back. We do expect our 2013 CapEx program to be cut back but because of the impact of the JVs and the additional capital that comes from those joint ventures, our activity levels, as Dave said, will stay pretty high.

And the substantial part of the cutback is going to be on the leasehold side, not the drilling side. So we're going to be very active on the drilling side.

Got it. I appreciate that detail. I guess my follow-up is kind of related, and it really comes then to capital allocation and how you think about this very long term. Some of your competitors have talked about they are prepared to allow gas production to slide next year. I'm thinking specifically of EOG and Chesapeake. And on the other hand, if we look at where you're allocating capital outside of the U.S., and obviously, the lower 48 is going pretty well, but Canadian differentials continue to be under pressure and if you listen to what the refiners are saying, they're anticipating that is going to stay that way for quite a while. So I'm just kind of wondering as to now that you -- you've had the exploration success in the lower 48, how do you see balancing capital between Canada, particularly longer term on Pike relative to accelerating the lower 48 until things shake out in terms of where those differentials are going to be because obviously, it's a number we are trying to get our heads around to what is sustainable going forward by way of differentials?

Well, Doug, in Canada, as you are probably aware, we are not spending a large amount or not allocating a large amount of our capital into areas -- into the conventional. We had very little activity there. And so almost all of our expenditures in Canada have been towards these heavy oil projects. And as you know, they are very, very long term in nature. So for example, Jackfish 3, I think Dave mentioned, we're about 47% completed or 45% completed on that. That's going to continue over the next couple of years. And as we move into Pike, we'll do our detailed engineering and won't even start that for over a year. And so we're really taking a much, much longer view on that than where the differentials may be over the next couple of years. So I think that we're pretty committed to that program in Canada. We really think that the heavy oil program in Canada -- we really think that Pike and Jackfish are in a very, very good part of the Oil Sands where we can have very good results over time. We will continue to allocate some significant funding to that.

Then on gas drilling, on the production network, if you can care to give a few words about that.

Yes, and on the gas side, yes, we're really focusing on the higher-margin products. And so where we're drilling gas, we're drilling liquids-rich gas, trying to drill in the areas where those liquids are -- the ones that are providing the best returns. And if that drops off our gas a little bit, then we're not -- that doesn't concern us.

Next question comes from the line of Dave Kistler from Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Probably a bit early to be asking this with the election just behind us, but can you give us kind of latest thoughts or kind of plans with respect to repatriation of capital? And maybe even in the past, you've talked about divestitures of this Canadian assets that it sounds like you might be moving to development programs. So color on both of those would be very helpful.

Well, Dave, this is Jeff Agosta. I'll take a crack at the first one there about the repatriation. As we've said repeatedly that we will wait to see how the legislation process plays out. I think that it's prudent to see how any compromise gets made with Congress and the Administration on the tax front. So we're still hopeful that we get some rational tax legislation out of our government, and it's prudent to wait. And I think it's also important to note that our financial flexibility is not at all impeded by that. We're able to borrow in the current short-term markets at very attractive rates. So it just makes sense to wait it out.

And on the other side, Dave -- on your other question, we've been -- we're very open to everything that's going to create value. I think we always we have been. We've never been shy about that. We've taken some bold moves, and so we're always looking at ways to increase value. So I can't tell you anything specific, but we're looking at all of our assets and making sure that we manage them in a way that over time creates the most value. David W. Kistler - Simmons & Company International, Research Division: Great. I appreciate that. And then this kind of follows up, and Jeff maybe touched on it a little bit, but thoughts with respect to cash outflows in terms of either providing increased dividends or share buybacks or -- going to have to think about that relative to legislation and use of capital.

Dave, we've been very consistent over the past, I don't know, 8, 10 years of increasing our dividend and being very shareholder-friendly through buying back 20% of our outstanding stocks since 2004. We've consistently raised the dividend every year with the exception during the financial crisis in 2009 and 2010 when we were going through our repositioning, and we will continue to look at that. All with the view toward maximizing cash flow per share adjusted for debt.

Yes, Dave, this is Vince. I might add that really, the thoughts around the share repurchases are undertaken in conjunction with our capital budgeting process, which is currently underway.

Next question comes from the line of David Tameron from Wells Fargo.

Can you guys talk about -- at the Analyst Day you laid out the 5-year CAGR, 6% to 8%. Can you talk about any change given -- I know there's been some temporary disruptions, but given some of the disruptions of the production this year, can you -- any change to that longer term?

David, I think you're referring to the Analyst Day, we gave an illustration of what our assets could do under a specific set of assumptions. Those assumptions included price outlook, price realizations relative to benchmarks and the performance of our assets. If you look at things that have changed since that date, we've got NGLs, and our expectations for NGLs as a percentage of WTI have come down. I think gas prices have probably ticked up a little bit. Oil prices are a little weaker. And the changes to our portfolio, we've seen the delay in Jackfish ramp-up, should not affect the multiyear period, and we've also seen some good progress and derisking in some of our major oil plays. So all those things go into the mix. I mean ultimately, how much we grow top line depends on how much capital we spend, and we're always trying to optimize the per share growth, not the top line growth, and it's a continually evolving picture.

All right. Okay, and let me follow up, let me go completely unrelated. In the Cline Shale, can you talk about where -- I know you're drilling on that Eastern Shelf, if you will. I assume that's where the Cline Shale -- can you say specifically what area of that acreage you're targeting? And the 5 horizontals you mentioned that are in various stages, can you just talk about where those have been drilled? What counties?

Sure. The plan is to get a good representation of wells across our entire acreage position so we can evaluate it all. The first 3 wells that we have drilled have been located in Sterling County. Since that time, we have actually gone up and drilled a Mississippian well that I mentioned up in Fisher County where we have quite a bit of acreage as well. And we have a couple wells that we're currently drilling and completing in Mitchell and Nolan County as well. And so if you look at our acreage position, it is -- those are the 4 main counties where we have, at Sterling, Mithcell, Nolan and Fisher, with a little bit in Scurry County as well.

The next question comes from the line of Brian Singer from Goldman Sachs.

On the county acreage portion of your CapEx budget, how much is that now up to for 2012? Do you see and/or expect additional joint ventures to offset at some point some of that? And as we look ahead to next year, it seems like over the last couple of years, there have been a number of upward revisions to your budget for the purposes of acquiring acreage, is there anything different now in terms of thinking about a year from now having a budget that is meaningfully down versus first of 2012?

Brian, this is Vince. I'll take the first part of the question. The acreage spend this year is about $1 billion before any recovery through the JVs, that's the gross number. Year-to -- that's through the first 9 months of the year.

And then there will be another $200 million coming in the fourth quarter, so $1.1 billion -- $1.2 billion?

Well, we've recovered about $1.3 billion upfront from the 2 JVs this year.

No, his question was the incremental spend. We've spent $1 billion in the first 9 months, we've said another $200 million in Q4, is that a fair estimate?

That's correct.

Brian, on the joint ventures, we are developing some additional areas, if they're right for it. I mean, these joint ventures have been very good for us, and we hope good for our partners, and it's something that we will continue to be open to. It certainly improves our capital efficiency. It's something that we would do, and we have allocated a lot to capital or to leasehold over the last couple of years. And when you think about it, as we got out of the international and deepwater and moved onshore, we always said that we would take some of those funds. And I think we got a good return on our investments internationally and in the Gulf of Mexico. And we said we'd take some of those funds and reinvest them in a project onshore to continue to build a good inventory of future growth, particularly on the oil side, and that's what we've been trying to do. So I think it's been a judicious reallocation of proceeds of those dispositions. And now we have a pretty big asset base when you think about it, and we're pretty excited about a number of the areas and optimistic about the number of these areas, not the least of which is the Mississippian and the Cline and some of the things that we're doing in the Rockies. So we've got a lot of running room right now.

That's great. And I guess going to Canada and in Jackfish, with the 2 wells or the 2 pads that are kind of having issues, are you confident that, that is just isolated to those 2 areas, or do you see any wider implication for either of the pads that you're drilling or kind of thinking about some of the other leases like Pike?

We're very confident we understand now what the issues are that created this. And really, you could see it on the logs that there was some interbedded nature to the logs. What was not fully understood until we started producing. And remember, these pads were originally designed and approved from a regulatory standpoint 4 to 5 years ago when -- what was not fully understood is just what were the impact of this interbedded sands and shale have on the initial steam chamber development. So we're confident now. We understand that. We've seen this. We've actually observed it with not only here, but at Jackfish and some other industry projects in the same area. So the fact that this happened, we understand the nature. We're confident we can overcome this. The reserves are there. We're still going to get all the reserves? There's just a delay on these pads and getting the production up to full speed, and we know how to place future pads to avoid these issues.

And one other thing, Brian, I'll just throw in to what Dave has said is it's important to understand that as we drill additional couple of well pads, all we're doing is moving that capital forward. We're not adding a bunch of capital, and that's because over time we do believe that we'll recover all of the reserves in these first 2 well pads. So it's not like we're adding a bunch more wells, we're just moving them forward.

And I'd like to add we're very confident still that Jackfish and the Pike areas are really top tier projects. If there was as a mistake that was made, it's just we didn't add enough spare wells initially to make sure that the plant was full. But from a geological perspective, there is no question these are top tier reservoirs in the best part of the SAGD development.

The next question comes from the line of Charles Meade from Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: A question, and this is maybe for Dave. On the LOE coming in lower than expected, is there room for that to continue to go lower, or is it projected to bounce back up? I note that you didn't change your guidance on the LOE, but you can just talk about in general terms?

I would not expect the LOE to go lower. We are very proud of our performance on LOE because even as we're making the shift to a higher oil percentage as part of our overall production, everybody knows that oil is more expensive to operate than natural gas. And so the fact that we've been able to really mitigate the impact of that through our LOE is good. But because we are continuing to shift to more oil as a higher percentage of our production, I wouldn't anticipate it going lower on a per barrel basis. But we -- it's something we work every day, and we think we're pretty darn good at. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. That's exactly the detail I was looking for. And then the second question, this goes back to Jackfish a bit. As I look back in my notes from the Analyst Day, I think back then you're expecting to go post-payout in late '12 and that's now shifted into '13, and I guess that would make sense because oil prices are a little lower, have been lower than they were then. But does that then give you a little bit higher oil take in Q4 because of that? Or is that even a meaningful piece that we should think about?

No, we were expecting Brandon -- we were expecting payout -- I'm sorry Charles, we were expecting payout in at right around year end. And so it really doesn't have an impact on fourth quarter expected oil production. And now we expect it to be some point in the first quarter, not exactly sure when. It will depend on oil prices.

The next question comes from the line of Robert Christensen from Buckingham Research.

First question is on a few of the structural things that hurt Canadian differentials and pipeline projects, are you optimistic about more Canadian pipeline projects, Enbridge and Keystone, working in your favor of the next couple of quarters, years? I mean, what intelligence do you have that, that's happening? And then I guess on the demand side, the upper Midwest refineries, are those enlarging, expanding on schedule to close differentials?

Bob, this is Darryl Smette. Yes, obviously, as we went through this year, we had supply of heavy oil and pipeline capacity, refining capacity pretty well in balance, actually had a little bit more pipeline capacity and refining capacity than we had supply where we had a number of unplanned outages both in terms of refineries and pipelines in the second and third quarter that widened those differentials. They really started to improve in September as some of that unplanned outage come back on in some of the pipeline capacity come back on. So differential, as Jeff mentioned there, starting in September, and there pretty significantly through September, October and into the first part of November. As we got to the middle of November, we have both in the U.S. and Canada about 1 million barrels a day of refining capacity that has went down for turnaround. And so we have again seeing those differentials widened about $10 to $12 a barrel. That refinery maintenance should be completed sometime early in the first part of the first quarter of next year, so we should get that refinery capacity back. In addition to that, we have 2 refineries that are coming onstream, one in December, a Marathon refinery in Detroit is going to bring about 80,000 to 90,000 barrel additional refining capacity. So that's coming on, and then the Whiting Refinery that's converting to heavy oil should be on sometime in the second quarter. That's about 250,000 to 270,000 barrels a day of capacity. So although we're seeing some increase in production in heavy oil, the increase in pipeline refining capacity is actually exceeding what we're seeing in production. So we do think as we get through the first quarter, we will start to see some downward pressure on those differentials. In addition to that, we are actually seeing an increase in rail activity out of Canada. It's actually increased from about 800 rail cars a day up to about 1,100 to 1,200 rail cars today. A lot of that oil is being railed to the west coast and the east coast they is close in that going to the Mid-Continent so we have a combination of things that are looking better as we get through the fourth quarter and the first quarter of next year as we get in the second quarter of 2013 and beyond, start to look a lot better.

And my second question is -- maybe Vince answers, I don't know, Jeff answers, the cash flow per debt adjusted share, do you have that calculation for the third quarter versus a year ago? Has it been growing, that metric, has it been improving?

We're -- first of all, I don't have it in my fingertips. We do monitor that, and the prices have a huge impact over the short term, as well as our product allocation, but I can't give you that comparison right off.

I would say yes, that due to product prices being much lower in the third quarter of this year than they were last year, it has probably gone down for us and the industry.

We've run past the top of the hour, so we're going to respect your time and cut the call off. And as usual, we'll be around the rest of the day. The IR staff will be available to answer any follow-up questions. So thanks for your participation.

This concludes today's call. Thank you for your participation. You may now disconnect.