德文能源 (DVN) 2012 Q2 法說會逐字稿

Welcome to Devon Energy's second-quarter 2012 earnings conference call. At this time, all participants are in a listen-only mode. After the prepared remarks, we will conduct a question and answer session. 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 welcome, everybody, to today's second-quarter 2012 earnings call and webcast. Today's call will follow our usual format. I will provide a few preliminary items and then turn the call over to our President and CEO, John Richels, for his review. Then Dave Hager, head of Exploration and Production, will provide the operations update. And following that, our Chief Financial Officer, Jeff Agosta, will finish up with a review of our financial results and outlook. After Jeff's call, we will have a Q&A session and our Executive Chairman, Larry Nichols, as well as Darryl Smette, head of Marketing and Midstream, are with us today to help out with the Q&A session. As usual, we will conclude the call after an hour, so if we do not get to your question during the Q&A, we will be around for the remainder of the day to answer your questions. A replay of this call will also be available later today on our website.

During the call today, we are going to update some of our forward-looking estimates based on the actual results that we have seen in the first half of the year, and our revised outlook for the second half of 2012. In addition to the updates that we are providing during the call, we will file an 8-K later today containing the details of our updated 2012 estimates. To access this guidance, just click on the guidance link found in the Investor Relations section of the Devon website. Please note that all references today to our plans, forecasts, expectations and estimates, are forward-looking statements under US securities law. And while we always strive to give you the very best information possible, there are numerous factors that could cause our actual results to differ from those estimates. A discussion of risk factors relating to these estimates can be found in the 8-K that we are filing later today. Also in today's call, we will reference certain non-GAAP performance measures. When we use these measures, we are required to provide related disclosures, and those are also available on the Devon website.

Looking briefly at our earnings for the quarter, the first-call mean estimate for Devon's second-quarter earnings was $0.81 per share. That compares to actual non-GAAP earnings from continuing operations of $0.55 per share. So clearly, we had a big earnings miss for the second quarter. By far, the largest driver of the miss was wider product price differentials. These low price realizations also negatively impacted our midstream earnings. And to a much lesser degree, our results were negatively impacted by production interruptions that reduced our second-quarter production by 16,000 barrels per day average for the full quarter.

The most significant occurrence was a longer-than-expected partial shutdown for maintenance and repairs at our Bridgeport facility in North Texas. That work has now been completed. This reduced our NGLs production by approximately 10,000 barrels per day in the quarter, while disruptions at third-party facilities in the Permian basin, Mid-Continent and Gulf Coast regions contributed to the reduced volumes as well. As of today, all of the issues that interrupted production have been resolved. At this point, I will turn the call over to John Richels.

Thank you, Vince, and good morning, everyone. While our second-quarter earnings fell short of our expectations, when you look beyond the near-term challenges, we stayed right on track with the execution of our long-term strategic plan. We continued to deliver strong growth in oil production, driving company-wide oil production up 26% over the year-ago period, and up 5% over the first quarter of the year. In spite of unusually weak Canadian oil price realizations, oil revenue accounted for almost 60% of our upstream revenues in the second quarter. Given the weakness in the NGLs market, it is worth noting that ethane accounted for only about 4% of our second-quarter sales. In April, we closed our $2.5 billion joint venture agreement with Sinopec. You might recall that the transaction price included a $900 million cash payment at closing, recovering significantly more than 100% of our land and exploration costs associated with these assets. The remaining $1.6 billion drilling carry will fund 80% of the capital requirements on the joint venture assets over the next few years.

Also, in spite of weak second-quarter price realizations for much of our production, operating cash flow for the quarter exceeded $1.4 billion. And when you combine that with the proceeds from our Sinopec joint venture, total cash inflows approached $2.3 billion. Additionally, we added some attractive hedges, which will stabilize cash flows in the second half of the year. We now have approximately 85% of our oil production locked in, with an average protected floor of $97 per barrel, and 65% of our natural gas production protected at $3.76 per Mcf. And finally, we executed a robust oil-focused capital program while maintaining one of the strongest balance sheets and best liquidity positions in the peer group. We exited the quarter with $7 billion of cash and short-term investments and a net debt to cap ratio of about 14%.

As many of you are already aware, we also have some exciting news on the exploration front. Earlier this morning, we announced a $1.4 billion agreement with Sumitomo to explore and develop our 650,000 net-acre position in the Cline and the Midland-Wolfcamp Shale plays. Sumitomo will invest $340 million in cash at closing and receive a 30% interest in these properties. Additionally, Sumitomo will fund a little over $1 billion -- it is actually $1.025 billion of Devon's share of future drilling costs associated with these plays. This agreement will materially enhance our future returns and accelerate our evaluation and development of these assets, while leaving us with the land position approaching 0.5 million acres that represents very significant growth opportunity for Devon. And finally, like our joint venture with Sinopec, this partnership affords us the flexibility to invest more of our operating cash flow in our development opportunities, and to pursue additional oil prospects already identified by our technical staff. For years, we have enjoyed a strong working relationship with Sumitomo. Sumitomo is really a terrific company, and we look forward to working together for years to come through this mutually beneficial joint venture.

And speaking of additional oil prospects, during our Analyst Day in April, we mentioned that we were working to put together a significant lease-hold position in an oil prospect that we were not yet ready to disclose. Today, with that acreage position largely assembled, it is now ripe for disclosure. It is in a play that has received a lot of attention lately, with some very encouraging results. We have acquired an additional 400,000 net acres in the Mississippian Trend outside of the area that is covered by our Sinopec joint venture. When you combine our position in the Sinopec JV with this new position, we now have over 545,000 net acres in this emerging oil play. So just to reiterate, this 400,000 net-acre position that we are announcing today is not currently part of any joint venture. So between the Cline Shale position and the Midland Basin and our position in the Mississippian play, we have about 1 million acres net-to-Devon in two oil plays that appear to be working very, very well. We believe that this gives us years of oil growth beyond the light oil development projects that are currently driving our oil growth in the United States.

Shifting gears now, we have received a number of questions recently regarding the current state of the market for natural gas liquids and whether this will impact our capital allocation. Since last quarter's call, market conditions for natural gas liquids have deteriorated further. Inventory builds over the last three months far exceeded industry expectations. This was due to a variety of factors. There were delays in petrochemical plant turnarounds. We had extended downtime at two Mont Belvieu fractionation facilities, and we had a delay in the ramp-up of a petrochemical plant that is expanding its ability to run on ethane. Given these higher inventory levels and new NGL supplies being brought onto the market, our outlook for NGL realizations has deteriorated somewhat since our last quarterly call, and Jeff is going to provide some detailed guidance later in the call about those realizations.

Looking beyond 2012, with new takeaway pipelines and fractionation capacity coming online, ethane supply in the market will likely outpace incremental demand until new cracker additions are operational around mid-decade. Since ethane prices track natural gas prices, as long as natural gas prices remain low, we would expect ethane prices to also be weak during this period. However, as natural gas prices improve, so should ethane prices. In addition, as new export capacity along the Gulf for propane becomes available later on this year, we expect to see our overall NGLs price realization stabilize. In any case, our firm transportation agreements and our dedicated fractionation capacity at Mont Belvieu will maximize the value of our NGLs production.

Based upon our evolving outlook for price realizations for natural gas and NGLs, our liquids-rich Barnett and Cana programs continue to deliver attractive returns. Of course in the current pricing environment, most light oil projects are delivering superior returns, and our light oil programs in the Permian and Mississippian are developing now to the point where we are ready to begin increasing activity levels. We have migrated several rigs to these higher-return light oil opportunities and plan to move additional rigs in the second half.

For the full year 2012, we expect to deliver oil production growth in excess of 20%, shifting our overall production mix to 40% liquids by year-end. We remain on target to meet our guidance of 253 million to 257 million barrels equivalent of production, although we are trending towards the low end of this range due to the gas processing curtailments experienced in the second quarter that Vince discussed earlier in the call. Looking beyond the current year's activity, we are in the beginning stages of planning for our 2013 capital budget and while it is a bit premature to provide much in the way of guidance, I can assure you that we will remain focused on maximizing growth and cash flow per share adjusted for debt. We are fortunate that our existing resource base provides us the flexibility to shift additional capital towards light oil opportunities. Our existing acreage base comprises some 5 billion barrels of risked oil resource, representing many years of high quality undrilled inventory. In addition, we are leveraging our portfolio through joint ventures to allow us to accelerate that growth.

So in summary, we remain excited about Devon's future and believe that we are well-positioned to compete effectively in any business environment. Our measured approach to the business, strong balance sheet, and high quality property base all position us to deliver on our long-term business plan. And so with that, I will turn the call over to Dave Hager for a more detailed review of our quarterly operating highlights. Dave?

Thanks, John, and good morning, everyone. While the second-quarter production was impacted by the gas processing disruptions that Vince and John mentioned, we continue to make good progress with the execution of our capital program. We delivered strong oil production growth in both the Permian and Jackfish. We also had encouraging initial well results in some of the new ventures plays.

Before we get to the highlights of the quarter, I will begin with a quick recap of CapEx. E&P spending totaled $2.1 billion for the quarter, bringing E&P capital for the first six months to $3.7 billion. Our 2012 capital program is front-end loaded, especially for lease-hold expenditures. But in any case, we are tracking toward the higher end of our previous guidance range of $6.1 billion to $6.5 billion. As a reminder, when we close the Sumitomo transaction, we will have received a total of $1.2 billion in cash this year that is not netted against this capital for reporting purposes.

Moving now to specific operating areas, starting in the Permian Basin, our Permian production averaged a record 58,700 barrels of oil equivalent per day in the second quarter, up 21% over the second quarter of 2011. Looking specifically at our Permian oil production, it grew 24% over the same period, with light oil now accounting for nearly 60% of our total Permian volumes. A key driver of our Permian oil growth continues to be our Bone Springs horizontal program in New Mexico. We have 6 rigs running and in the second quarter, we brought 19 Bone Springs wells online with average 30-day IP rates of 680 barrels of oil equivalent per day. With these wells generating returns north of 50%, they offer some of the highest returning opportunities in our portfolio.

To date, we have identified roughly 300 risk locations in the play representing several years of additional drilling inventory. Also in the Permian, we continue to have very good results from our two-rig program targeting the Delaware formation. We brought eight wells online during the second quarter. Of particular note was the Shaqtus 1H that had a 30-day IP rate of 1,500 barrels oil equivalent per day, including 1,263 barrels of oil. Like the Bone Springs, this play offers outstanding returns. We have approximately 200 risk locations remaining in the Delaware.

Last quarter, we told you about a successful Wolfcamp horizontal well we drilled in the heart of our Wolfberry acreage, located some-80 miles northwest of the Wolfcamp play in the southern Midland Basin. The Averitt 17H had a 30-day IP rate of 400 barrels of oil equivalent per day. In the second quarter, we drilled an encouraging follow-up to this well. After 12 days of production, the Tatia 49H, that is producing roughly 325 barrels of oil equivalent per day, including 280 barrels of oil. These encouraging results were giving us the confidence to take the horizontal Wolfcamp play on our Wolfberry acreage into full development. And we also plan to test the middle Wolfcamp in the same area later this year.

I will now move to the two Permian plays that comprise the joint venture with Sumitomo that we announced this morning. First, in the Cline Shale on the eastern flank of the Midland Basin, we have continued to add acreage and have now assembled some 556,000 net acres in the partnership. We began to assess the potential of this acreage during the second quarter with our first horizontal well in the play. The Stroman Ranch C-5H, located in Sterling County, had a 30-day IP rate of 300 barrels of oil equivalent per day. On most of the frack stages, we utilized gel fracks.

However, we did test a couple of stages with slick water, with very good results. Consequently, in our second horizontal well that is currently being completed, we are utilizing slick water for all of the completion stages and expect the higher IP rate. And while it is in very early stages of evaluation of our position, we are very encouraged that the Cline Shale will be a highly economic oil play. We will continue to refine our drilling and completion techniques on the remaining wells planned for the second half of this year, and keep you updated as we move forward.

In the other play in the Sumitomo JV, the Wolfcamp Shale in the southern Midland Basin, where we have 94,000 net acres, we brought three Wolfcamp horizontal wells online in the second quarter. These included the Coronado 2H, with an average 30-day IP rate of 575 barrels of oil equivalent per day. Subsequent to the end of the second quarter, we tied in our first 7,000-foot lateral completed with a slick water frack. After 22 days of production, the University 52-10H well has averaged 650 barrels of oil equivalent per day, including 575 barrels of oil. We are obviously very encouraged by these results. We currently have two rigs running in the Wolfcamp Shale and two in the Cline. The joint venture with Sumitomo will allow us to accelerate the evaluation and de-risking of these plays. We expect to drill 28 wells in these two plays in the remainder of 2012, bringing the total number of wells drilled or participated in to 40.

Shifting now to our thermal oil projects in eastern Alberta, aggregate production from our two producing Jackfish projects averaged a record 51,100 barrels of oil per day net-of-royalties in the second quarter. Jackfish 1 continued its trend of best-in-class plant reliability and efficiency, achieving a plant utilization rate over the past 12 months of more than 98%. We will bring the Jackfish 1 plant down for scheduled maintenance beginning in early September. This is something we do roughly every two years. We expect the maintenance turnaround to take about three weeks. When we restart the plant, it takes about three to four weeks to ramp production back up to capacity.

Accordingly, our net Jackfish 1 production is expected to average about 23,000 barrels per day in the second half of 2012. At Jackfish 2, production is on pace to reach more than 25,000 barrels per day before royalties by year-end, and to reach facilities capacity in 2013. Jackfish 3 construction continues to progress well, with roughly 40% of the projects complete, putting us on track for a startup around year-end 2014.

At Pike, we filed an application for a regulatory approval in late June for the Pike 1 development. The Pike 1 application is for a project with a gross production capacity of 105,000 barrels of oil equivalent per day. We continue to work with our partner on the details of the development plan and expect to finalize those later this year. We operate Pike with a 50% working interest. As a reminder, we expect our existing SAGD assets to drive Devon's net thermal oil production to more than 150,000 barrels per day by the end of the decade.

On the exploration front in Canada, we continued to evaluate the oil- and liquids-rich gas potential across our more than 4 million net acres. Our most encouraging results over the last 18 months of exploratory drilling have been in the Ferrier Corridor, where Devon has roughly 240,000 net acres prospective for the Cardium oil, the liquids-rich glauconite, and other lower Cretaceous zones. To date, we have drilled a total of 19 operated horizontal wells in these formations. Average 30-day IP rates have ranged between 300 and 400 barrels of oil equivalent per day, with drill and complete costs in the $4 million to $6 million range, these wells have strong economics and we are currently evaluating a potential development plan for these areas.

Shifting to the Barnett Shale field in north Texas, based upon the early success we are seeing in the Mississippian oil play in Oklahoma, we recently moved two of our Barnett rigs and three of our Cana rigs to the Mississippian. This leaves us with 10 operated Barnett rigs running in a liquids-rich core and the oil window in Wise County, and 12 rigs running in core-rich Cana. As Vince mentioned earlier, our reported volumes were impacted by an extended maintenance turnaround of our Bridgeport natural gas processing plant in the Barnett. In spite of this curtailment, our second-quarter net production from the Barnett averaged 1.32 Bcf equivalent per day, up 3% from our second quarter a year ago.

Moving now to the Cana-Woodford Shale in western Oklahoma, in spite of some minor disruptions at third-party processing facilities and a temporary increase in uncompleted wells due to pad drilling, we still achieved an all-time production record at Cana. Second-quarter 2012 production increased 48% over the year-ago quarter, and 3% over the first quarter of 2012. Cana's second-quarter production growth was led by oil and NGL growth of 59% over the year-ago quarter, to 3,500 barrels of oil and 10,400 barrels of natural gas liquids per day. Moving west to the Texas panhandle, in the Granite Wash play, we continue to see solid results. We brought six operated Granite Wash wells online during the second quarter, with 30-day IP rates averaging 1,270 barrels of oil equivalent per day. We plan to move a fourth rig to the Granite Wash later this year.

In addition to some of the very encouraging results in the Cline and Wolfcamp Shale plays, we have some updates on some of our other new venture areas. Looking first at the Ohio Utica, our first two horizontal wells, the Eichelberger 1H in Ashland County and the Richman Farms 1H in Medina County were not encouraging. These wells are located on the northwestern-most acreage. We are currently completing our third well to the south, the Sinsabaugh 1H located in southern Knox County. This well offsets our initial Harstine Trust core well. We will continue drilling in a liquid-rich window to the east, where industry has about 20 horizontal rigs running.

In the Tuscaloosa Marine Shale, we drilled our first three wells in the northern portion of our acreage position. The Richland Farms 74H, located in East Feliciana Parish, was brought online in the second quarter, with an average 30-day IP rate of just shy of 300 barrels of oil per day. In our next well, we landed the lateral in a more optimal position and we saw significant improvement in rate. After 20 days of production, the Weyerhaeuser 14H in St. Helena Parish has averaged 670 barrels of oil per day from a 5,700-foot lateral. Our third well in the area, the Murphy 63H in West Feliciana Parish, a 4,700-foot lateral, is slated to begin completion operations early next week. We plan to drill our future Tuscaloosa wells with 8,000-foot laterals. We expect this trend of improving performance to continue, as we make additional improvements to our drilling and completions. Reducing costs and improving well performance over time are keys to making this play economic going forward.

In Michigan, the results from our first two A1 Carbonate horizontal wells have not been encouraging. Each of these wells appear to be tight. These wells were drilled in close proximity to each other in a central portion of the basin. So our plan going forward is to test the A1 and Utica potential on the outer flanks of the basin in the remainder of the year with a two-rig program.

In the Rockies oil exploration, as we previously indicated, we are testing a number of objectives in the Powder River and DJ Basin. Since we last updated you at our Analyst Day, we have drilled one well in the Mowry, three in the Niobrara, and one in the Codell. All these wells are in various stages of completion. We are currently drilling a follow-up to the successful Turner well we drilled earlier this year. As a reminder, this well had a 30-day IP of 433 barrels of oil equivalent per day.

Finally, in the Mississippian oil play located in north-central Oklahoma, we have now expanded Devon's position to 545,000 net acres, including about 150,000 net acres within the Sinopec JV. The recently added acreage is predominantly north of our initial position in Noble, Osage, Grant, and Sumner Counties. This is a play that has attracted add great deal of industry attention due to attractive returns, the high quality of oil it produces, and the established, relatively industry-friendly regulatory environment in Oklahoma. We currently operate or have an interest in 52 Mississippian wells that are drilling, completing or producing. And we are expanding our operations quickly. We have seven operated rigs running in the play and expect to add additional rigs later this year.

Our results continue to support a type curve, with a 30-day IP of roughly 300 barrels of oil equivalent 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 a large position that will add many years of drilling inventory for us. And this is a position that can truly move the needle for a company of Devon's size, with net risked potential of more than 800 million barrels of oil equivalent. So in summary, our 2012 capital program continues to drive strong growth in oil and natural gas liquids production, while simultaneously evaluating a wide range of exploration prospects. With that, I will turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

Thanks, Dave, and good morning, everyone. This morning, I will take you through a brief review of the key drivers that shaped our second-quarter results and where called for, provide updated guidance for the second half of the year. Beginning with production, our second-quarter reported production totaled 61.8 million oil equivalent barrels, or 679,000 BOE per day, a 3% increase compared to the same period a year ago. This result is about 6,000 barrels per day, or 1% shy of the lower end of the guidance range we provided last quarter. As Vince mentioned earlier, interruptions of midstream facilities reduced our second-quarter volumes by approximately 16,000 BOE per day. Had these outages not occurred, production would have been at the top end of our guidance range.

Fortunately, the disruptions impacted only gas and NGL volumes, so our oil production was on target. For the quarter, our oil production increased by 26% over the second quarter of 2011, to an average of 149,000 barrels per day. Strong year over year growth in the Permian and Jackfish drove the performance. For the third quarter, we expect production to increase to a range of 680,000 to 690,000 barrels per day, in spite of the plant turnaround at our Jackfish facility. The turnaround at Jackfish will reduce oil volumes by approximately 10,000 barrels per day in both the third and fourth quarters. Even with these curtailments, we still expect that our oil production will increase more than 20% in 2012.

Moving to price realizations and beginning with Canadian oil, supply and demand for Canadian crudes remains very tight. Consequently, any disruptions in refinery capacity or pipeline take-away can have a dramatic effect on pricing. This has resulted in increased price volatility and has made it difficult to predict price realizations. In the second quarter, Canadian oil realizations came in at 59% of the WTI benchmark, or just below the lower end of our forecasted range. The wider second-quarter differentials were attributable to extended maintenance downtime at Midwest refineries and various outages of third party pipelines.

In the second half of the year, we expect turnarounds at three major Midwest refineries to continue to place pressure on our crude realizations. With this in mind, we now expect our Canadian oil realizations to range between 50% to 60% of WTI for both the third and fourth quarters. An incremental 80,000 barrels a day of refining capacity is expected by year-end, with an additional 240,000 barrels a day by the middle of next year. These additions should significantly improve the supply-demand situation. Given the challenges that John discussed for the NGL market, we now expect that our third-quarter NGL realizations will range between 28% and 34% of WTI.

On the natural gas side, our second-quarter Company-wide price realizations came in below the low end of our guidance range at approximately 80% of Henry Hub. Regional differentials widened in most of our producing regions in Canada and the United States during the quarter. Prices were especially weak in the Mid-Continent region. For the second half of this year, we expect that our gas price realizations will average 75% to 80% of Henry Hub in the US, and 80% to 85% of Henry Hub in Canada.

Turning briefly to our marketing and midstream operations. In the second quarter, weak gas and NGL prices, coupled with a planned shutdown of our Gulf Coast fractionators facility in Mont Belvieu to expand its capacity, reduced our midstream operating profit to $68 million. Now that the expansion of the facility is complete, we expect our midstream operating profit to rebound to a range of $90 million to $110 million in the third quarter.

Moving to expenses, in the second quarter, lease operating expenses came in at $8.30 per BOE. This represents a 2% increase compared to last quarter. Had we not experienced any production interruptions during the quarter, our per-unit expenses would have been flat compared to the first quarter. This is noteworthy, given our growth in oil production which, as you know, is generally more expensive to produce than natural gas. Looking ahead to the third quarter, due to the scheduled maintenance at Jackfish, we expect LOE to approximate $8.50 per BOE. For the full year, LOE should still fall within our previous guidance range.

Our second-quarter G&A expenses were $176 million, a 5% increase over the previous quarter. The quarter over quarter increase is almost entirely attributable to the implementation of our new Company-wide software platform. For the most part, these implementation costs are non-recurring. Therefore, we are forecasting third-quarter G&A expenses to decline to a range of $160 million to $170 million. Our full-year forecast for G&A expenses also remains unchanged.

Shifting to interest expense, in early May, we took advantage of attractive market conditions to issue $2.5 billion of senior notes. We issued a combination of 5-, 10- and 30-year notes, with respective coupon rates of 1.875%, 3.25% and 4.75%. We utilized these proceeds to reduce our short-term borrowings. Interest expense totaled $99 million for the second quarter, a $14 million increase over the prior-year quarter. This increase is almost entirely attributable to the impact of the bond offering. For the remainder of the year, we expect our interest expense to range from $110 million to $150 million per quarter. DD&A expense for the second quarter totaled $684 million, or $11.07 per BOE.

For the second half of this year, we expect our depletion rate to range between $11.20 and $11.60 per BOE. However, if natural gas prices remain depressed, we would also expect to incur a full-cost ceiling write-down in the third quarter related to our US oil and gas properties. Just as a reminder, this is a simple accounting exercise that generates a non-cash charge and lowers the Company's go-forward DD&A rate. In summary, our pretax cash costs totaled $14.39 per BOE in the second quarter. Had we not incurred the production disruptions, this figure would have been around $14 per barrel produced, or about 1% over the previous quarter. In any case, we continue to be positioned as a low-cost producer among our peer group.

The final expense item I will touch on is income taxes. After backing out the items that are typically excluded from analyst estimates, our adjusted second-quarter 2012 income tax rate was 35% of pretax earnings. This is similar to the tax rates we would expect for the remaining two quarters of the year. In today's earnings release, we provided a table that reconciles the effects of items that are typically excluded from analyst estimates.

Before we open the call to Q&A, I will conclude my remarks with a quick review of our financial position. During the second quarter, our cash flow from operations totaled $1.4 billion. Combined with the $900 million of proceeds from our Sinopec joint venture, our total cash inflows reached $2.3 billion. This cash allowed us to comfortably fund our robust capital program while maintaining excellent financial strength. As mentioned earlier, we exited the quarter with a net debt-to-adjusted cap ratio of only 14%, and cash and short-term investments of $7 billion. Clearly, from a balance sheet and liquidity perspective, we remain exceptionally strong. At this point, I will turn the call back to John.

Thank you, Jeff. In summary, while second-quarter earnings were impacted by low price realization and downtime at the midstream facilities, our operating results continue to reflect the successful execution of our plan. We delivered year over year oil production growth of 26%. Our exploration program delivered encouraging results in the Mississippian Trend and the Cline Shale. And we also opportunistically added to our acreage position in both of these promising opportunities. We comfortably funded a robust capital program while maintaining an exceptionally strong balance sheet. Subsequent to quarter-end, we announced a $1.4 billion joint venture agreement with Sumitomo to explore and develop the Cline play. And finally, we remain fully committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength, and optimizing our growth and cash flow per share on a debt-adjusted basis. So with that, I will turn the call back over to Vince for the Q&A. Vince?

Operator, we are ready for the first question.

Scott Hanold, RBC Capital Markets.

Thanks, good morning. Congratulations on the Permian deal. A question on the Cline Shale. What does the infrastructure need there right now? And is part of this development, or I'm sorry, the joint venture, cover development of some of the infrastructure out there?

Yes, this is Darryl, and I will answer that. The whole Cline Shale, it is a big area, obviously. There is a lot of the area out there that really has no infrastructure at all, in terms of pipelines, gas processing plants, things of that nature. So infrastructure definitely in a lot of these areas will have to be built. There are a few little areas in Sterling County where there is some infrastructure, and some of the wells that Dave talked about that have been drilled there are close to that infrastructure.

But in general, you know, when we go forward and think we are going to have success here, infrastructure will be an area that we have to focus on. Either Devon, in terms of its midstream operations, or a third party, or a combination thereof. The agreement with Sumitomo allows them to participate in midstream activities, if we choose to go forward with that, or if they choose to go forward with that. So that would be an option for them. But right now, that decision, whether they would participate in any midstream facility, has not been made by them.

Scott, this is Dave. I might just add, this is an area, though, where thousands of wells have been drilled historically by the industry. So as far as ongoing ability to drill and complete wells, there is an infrastructure that works for that. What Darryl was addressing earlier is obviously accurate from the midstream facility side.

Understood. So are the 40 wells that you are drilling targeting areas where some more of the development infrastructure is at this point? Or are you going to spread them across the play just to delineate better?

Well, right now, it looks like it is going to be some of both, so we can test the play from a wider context. But some areas are going to have a little bit of infrastructure, and some of the wells that we will drill probably will not have the infrastructure right now.

From a midstream perspective --

From a midstream perspective --

Yes, that is what he is answering. But we are testing a good portion of our acreage to just get an idea of the prospect area of various parts of our acreage.

Okay. And as a follow-up on the Mississippian play, you are moving some rigs in there. How are you allocating those rigs versus your new acreage, versus the stuff you're doing with Sinopec? How does that work?

Well, we have drilled a number of wells on the Sinopec acreage. We are now moving the rigs for the current time up to the new acreage. And that is where our rigs are located presently. And we will probably continue to evaluate both of those areas throughout the rest of the year.

Okay. So you have got seven rigs in there, in the play right now. How many are in the JV versus your own acreage and what would you --

Seven. Right now, we have all seven rigs working in our own acreage, and none in the JV acreage. We do anticipate we will be moving back into the JV acreage later this year, though. And I can't give you an exact count. We are continuing to still ramp up our activities. But we are going to have significantly more rigs working by the end of the year than we have working now. But, Scott, I think it would be a little speculative to go exactly how many rigs or exactly where they would be located. But I think that you will see for the rest of the year that we will have rigs working in both areas with increased rig count.

Okay. When you say -- just as sort of a ball park, when you say significant, are you saying maybe like doubling the rig count from where you are at right now? Is that sort of a ball park?

That is certainly very possible, Scott.

Okay, understood. Thank you.

Stephen Shepherd, Simmons & Co.

Good morning. I was just wondering, to what extent has ethane rejection led to MidCon Basis maybe coming in weaker relative to other parts of the country, and subsequently driving the weakness at the corporate level you all had at gas realization in Q2?

I'm not sure I understood the question. Could you repeat it, please?

So with ethane rejection, I mean, is the fact that ethane is not going into liquid stream, moving back into the dry gas stream, is that at all exacerbating the problem that you are seeing in the MidCon, or is it strictly just higher gas production that is driving that?

Okay, thank you. You know, that probably has a little bit of an impact, but not a lot of impact, I don't think. Our view is that there is probably somewhere around 200 million to maybe 300 million of additional volume, primarily in the Mid-Continent as a result of ethane being rejected. And as you very well know, ethane prices in Conway have been down to $0.02 or $0.03 a gallon, so there has been some rejection there. But the overall impact, while there is some, I think that is been very, very minor based on what we can tell.

Okay, that's great, thanks. On the mist line, the new acreage, can you disclose the price you paid per acre there?

You know, in areas where we are still looking at prospective acreage acquisitions, we generally decline to get real specific.

Okay, that's fine. Then I've just got a couple more. Exploration CapEx, up pretty substantially quarter-over-quarter. Can you give us a little bit more visibility on the progression of that through the end of the year?

This is Jeff. That was -- we closed a lot of our acreage acquisitions in the second quarter, so that would be flowing through the exploration capital. And we indicated on our last quarterly call that we did expect Q2, the second quarter, to be very lumpy with regard to acreage acquisitions. And as Dave indicated, our capital program is more front-end loaded this year.

Particularly with regard to acreage. That's when we picked up the Cline Shale acreage, a lot of the Mississippian acreage, and so that's what you saw the impact of.

I know you know this, but I want just to remind you, as Dave pointed out, that from a reporting point of view, you know, we acquired this additional acreage. We brought in more than 100% of a lot of this acreage, and that doesn't get netted out from a reporting perspective. So that skews the capital numbers a little bit, because you don't see what -- the money that we're taking in on the other side.

Okay, thanks. And just one more. In the Midland-Wolfcamp and Cline areas where you executed the new JV, beyond 2012, what do you think the rig ramp might look like there? How many gross wells do you think you can drill in each of those regions going forward?

Well, we obviously need to see results first. And so it is somewhat speculative to, at this point, to go too far out. But you can see, when you put together an acreage position of 650,000 acres, like we have on this, we have anticipated a fairly aggressive ramp-up, if the results continue to perform as we expect and as we have seen. So I would see that -- I am not going to give you an exact number here, but you could -- because the economics are potentially very strong, you can anticipate a pretty strong ramp-up of rigs as we move into 2013. And of course we will be discussing that with our new partners and they are -- Sumitomo -- and they are anticipating this, as well.

Okay, great. And what is a good well cost to use in those regions? What have you seen there in terms of gross well costs?

Yes, gross well costs that we are using in the Wolfcamp Shale, we see on the order of around $6 million, $6.5 million or so in the Midland Basin so far. And very similar well costs that we've seen out in the Cline, as well.

Okay, that's all I've got. Thanks so much.

Brian Lively, Tudor, Pickering.

Hi. On the JV acreage, could you guys clarify how much production are you conveying with the deal?

It is minimal. Current production is less than 500 barrels a day that we would be conveying.

Okay, and then just more strategically, if we are trying to look at 2013 from a high level, given the commentary around NGL expectations from a pricing perspective, and some of the results from some of the newer exploration areas. Should we, one, assume that spending will be within cash flows net of deal proceeds? And with that, would we expect just incrementally more capital allocation to the MS Lime into the Permian and away from plays like the Barnett and Cana, perhaps the Utica, Michigan area?

Yes, Brian, let me take a shot at that. Obviously, we are early going into our 2013 planning. So, we haven't kind of crystallized all of that. You know, we are in the position that we can take some of those proceeds that we got from our offshore and reinvest them into onshore projects. All things being equal, though, as Dave has already said, we are reducing our rig count in places like the Barnett and Cana and moving them more into these light oil plays, just because of the economics.

But I do want to make the point that in the liquids-rich portions of the Cana and the Barnett, we still get some pretty darn good returns. When you are looking forward from this point, it doesn't really matter what gas prices are for '12 anymore. We are really looking at 2013 prices for all of our capital activities. And if you take a 375 Henry Hub price next year, which I think is pretty close to what Wall Street is using, and very close to the strip as well, so we're all in the same ball park -- once you take into consideration our midstream uplift and even at a 31% NGL realization, we are seeing a low 20s rate of return in the Barnett and then an almost 30% rate of return in the Cana.

So there are portions of those two plays that still make a lot of sense to the point that we can -- if we're going to focus in those best areas, we are going to move some of those rigs on to some of these new oil plays where we really have a whole lot of expectation and potential for the future.

Right. I was just thinking --

Oh, and the other question on living within cash flow. You know, again, over the last couple of years, we have taken some of those proceeds from the offshore and have reinvested them in rebuilding or changing, adding significantly to our light oil potential in the Company. We have done a lot of that and my guess is we are, you know, while we have the capacity to do it, with some uncertainty on the commodities pricing side, we will just have to be careful as we go into next year to make that final determination of how much we are going to spend. I think it is kind of early, but my guess is we will be trending towards our cash flow.

Okay. So I guess you are still saying that you might use some of the, I guess the $7 billion that you still have to fund some opportunities, even if it were to exceed your cash flow levels, or no?

Well, I think not to the extent we have. But we still have that capacity if we want to. We have added a lot and, as I was saying earlier, when you've got a million net-acres and a couple of highly prospective oil plays, we've got a lot of running room on those plays already. So, we are pretty happy with what we put together to this point in time.

This is Vince. I would add that the two JVs that we have entered into will allow us to get a lot more activity out of any given capital spend. So, we could achieve similar results of developing our core development plays while evaluating acreage and exploration plays with a reduced amount of capital.

I got it. Thanks, guys.

Brian Singer, Goldman Sachs.

Thanks, good morning. Going back to the Cline, can you estimate the impact of both costs and IPs that you think slick water would have, relative to the Stroman Ranch well you highlighted? And can you also talk about when you would plan to move drilling more meaningfully to the northeast within your acreage?

Well, as far as costs go, there will be a little bit of improvement in costs, but not a significant reduction in costs, relative -- in the overall well costs going to slick water. We can't say for certain how much improvement there will be going to slick water, but we have certainly seen in the Wolfcamp Shale that going to slick water is a cleaner frac. And we have seen much better results in the Wolfcamp Shale, and operators have gone to slick water primarily in the Wolfcamp Shale.

We think the Cline is very similar, and we know that some other operators also have recently moved to slick waters there also, and it appears they are getting better results. So we need to actually complete the wells to know for sure, but we are very optimistic that, based on all the other results we've seen in that area, we are going to see a pretty significant improvement. And again, we've just drilled one well on 650,000 acres so far.

So it is so early on that we are just very confident that we are going to be in the range, based on the other wells that we've seen drilled in the area. And we are going to be moving some of the rigs off to the northeast to test some of that acreage as well, later this year. So as I said, we are going to be moving the rigs around the acreage to get a good handle on what the overall prospectivity of various parts of the acreage position are.

Thanks. And then going over to the Utica, how committed are you to acreage retention in the two-thirds of your Utica acreage in the oil window, and do you see any differences in characteristics in the Knox County well versus the first two wells?

Well, we are committed to economics, and we were committed to really drilling wells that are going to meet our economic thresholds. And the first two were disappointing. It was on the far northwestern part of our acreage. We do see some -- because we offset -- we are essentially very near the original well where we took a core in that appeared to have good thermal maturity and good permeability. We are somewhat more optimistic in this well than we were the previous two wells.

But even more so, as we move to the east with our additional drilling activity that we're going to be doing throughout the rest of the year, probably drill about five more wells for the rest of the year, we are going to be moving more where the rest of the industry activity is. So that part of the acreage is probably even more prospective.

And Brian, and the other thing is, a couple of these plays, like that one, in that portion of the play, we always said this was highly exploration in nature. Because there wasn't a lot of experience by the industry. And it is one of the reasons why we got in there and acquired our acreage for a few hundred bucks-an-acre rather than thousands-an-acre. This is something that, as Dave has correctly pointed out, we are going to be driven by economics on this thing, not by a desire to hold acreage if it is not making sense in any portion of any play.

Great, thank you.

Bob Brackett, SMB.

I just have a follow-up on the question on Ashland and Medina. Have those two wells condemned the area, or are you going to go back and try some different things further down the road?

Well, those two wells were not encouraging in that immediate area. As exploration, you always have to drill more wells and each one you drill, you may learn some more things that could or could not make the acreage there work. But the first two wells were not encouraging. So we need to get more well results, and perhaps these additional well results will give us a reason to go back there. But we're not focused in that area right now.

But do you think it was the frack or the geology that failed on you?

We think it is geology.

Okay, so it is the geology. Another question I had, can you update us on the offshore cash? I mean, we've talked about it before. And also, would you have any appetite to look at international shales outside of North America, given you've got a war chest outside of the US?

Just an update on, Bob, on the offshore cash. We have -- all but a few hundred million dollars of the $7 billion is sitting offshore at this point in time. And so that hasn't really changed a whole lot since we talked to you before. As far as looking internationally, we are never closed-minded about it, but we have just repositioned the company to take advantage of our expertise in our portfolio in North America, and we've got an awful lot of really exciting opportunities ahead of us.

And, you know, with the things that we've added recently, I think we really want to get more into that and really understand the potential and, and develop this big asset base that we've got here before we start thinking of those other things. But you know us. We are never closed-minded about anything. But right now, I'll have to tell you we're not looking internationally because we really have a whole lot on our plate here that we think is going to provide us a lot of drilling opportunities for a long time.

Thanks.

Operator, we have got time for one more question.

David Tameron, Wells Fargo.

Good morning. Can you talk a little bit about Canadian asset sales and, I think you guys had mentioned at the Analyst Day you could potentially shed some assets up there. Can you talk about where you are at in that process?

David, as Dave said earlier, we have done a fair bit of exploration work here over the last little while. I think we're still evaluating our position in Canada. We've had some optimistic results I think on some of the acreage and we're just not ready to make a call like that at this point in time.

Okay. And let me take my follow-up with a different direction. Can you talk about -- there's rumors you guys were drilling up north, up near Abilene, and you guys are chasing not necessarily a Cline or Wolfcamp, but a Mississippian-type formation. Can you give us any -- or Mississippian Age formation. Can you give us some color on that?

No, we can't give you any color on that at this point.

Okay, fair enough. Thank you.

All right. Well, I show the top of the hour, so thank you for participating in our call today, and we will look forward to talking to you next quarter.

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