Devon Energy Corporation (DVN) Q1 2011 Earnings Report, Transcript and Summary

Welcome to Devon Energy's First Quarter 2011 Earnings Conference Call. [Operator Instructions] This call is being recorded. At this time, I'd like to turn the conference over to Mr. Vince White, Senior Vice President of Investor Relations. Sir, you may begin.

Thank you, operator, and good morning to everyone. Welcome to Devon Energy's First Quarter 2011 Earnings Conference Call and Webcast. For today's call, as usual, I'll begin with a few preliminary items and then I'll turn the call over to our President and CEO, John Richels. He will provide his perspective. And then Dave Hager, our Executive Vice President of Exploration and Production, will cover the operating highlights. Following Dave's remarks, Jeff Agosta, our Chief Financial Officer, will finish up with a financial review. We will follow with a Q&A period. And as usual, we'll hold the call to about an hour. Darryl Smette, who is our Senior Vice President of -- Executive Vice President of Marketing and Midstream; sorry, Darryl, and other senior members of management are with us today for the Q&A session. As always, we'll ask each participant on the call to limit his or her questions to one initial inquiry and one follow-up. A replay of the call will be available later today through a link on our Home page, that's www.devonenergy.com. During the call today, we will make some minor refinements to our forward-looking estimates for items such as production, capital expenditures and our hedge position. But since the revisions are so minor, we're not going to issue a new 8-K. We'll just post the changes to our Guidance page on our website. To find that, just click on the Guidance link found in the Investor Relations section of the Devon website. Please note that all references in today's call to our plans, forecast, expectations, estimates and so on are forward-looking statements under U.S. securities law. And while many factors could cause our actual results to differ from those estimates, we always strive to give you the very best guidance we can. We encourage you to review a discussion of risk factors if you're so inclined that is provided with our Form 8-K forecast. We will reference certain non-GAAP performance measures in today's call. When we use these measures, we're required to provide certain related disclosures and those disclosures can also be found on the Devon website. One final item, while our first quarter cash flow per share significantly beat the consensus estimate, our earnings per share from continuing operations came in about $0.05 shy of consensus. Production was better than expected and our pretax cost per barrel were lower than the midpoint of our guidance. However, our deferred taxes were higher than expected. Total adjusted income tax expense for the quarter of 34% of pretax earnings was 4 percentage points over the midpoint of our guidance. At this point, I'll turn the call over to our President and CEO, John Richels. John?

Thanks, Vince, and good morning, everyone. First quarter of 2011 was really an outstanding one for Devon. Our North American onshore production increased 7% compared to the first quarter of 2010, exceeding the top end of our guidance range. We achieved this year-over-year production growth in spite of first quarter production outages resulting from severe weather. In addition, production growth accelerated as we exited the first quarter. We're very confident that we will deliver on our second quarter 2011 production forecast of 645,000 to 655,000 equivalent barrels per day. This represents an increase of about 3.5% over the first quarter. We remain on track to deliver on our full year 2000 production forecast of 236 million to 240 million barrels of oil equivalent. And in addition, we expect to shrink our balance sheet with share repurchases and a reduction in net debt. This should drive our 2011 production growth per debt adjusted share to a rate in the mid-teens. Devon also delivered an excellent first quarter performance from a cost-containment perspective. Continued focus on cost containment, mitigated industry inflation and the impact of the stronger Canadian dollar. As a result, Devon actually saw a decrease in unit cost versus the year-ago quarter. As Dave is going to discuss later in the call, we continued executing on our North American onshore strategy with excellent results from our key development projects, and we also made some encouraging progress on the exploration front. In the first quarter, we generated $1.5 billion of cash flow before balance sheet changes. This cash flow from operations and the liquidity provided through our strategic repositioning comfortably funded our capital programs and returned nearly $800 million to our shareholders in the form of stock buybacks and dividends. Of the $3.5 billion authorized per share repurchases in May of 2010, we've now spent about $2.1 billion. We have purchased with that more than 28 million shares or just over 6% of our outstanding shares at an average price of roughly $73 per share. This brings our total shares repurchase since 2004 up to 95 million shares or roughly 20% of our shares outstanding. As we previously indicated, we expect to complete our share repurchase program by year end. I'm sure by now that most of you are aware of the recent statements to the press by Brazilian authorities indicating that approval of the $3.2 billion sale of our Brazilian assets to BP is imminent. Based on their statements, we expect this transaction to close within the next few weeks. With the strategic repositioning that we began in November of 2009 now substantially complete, I could not be more pleased with the results. The repositioned company has all of the attributes necessary to deliver superior per share growth. We're generating excellent full cycle returns, we have superior financial strength and we have a very deep inventory of highly economic low-risk development projects. The depths and breadths of our balanced North American property portfolio provides us with a compelling strategic advantage, the luxury of easily shifting capital in response to changing market conditions. Unlike many of our peers, we can focus our capital on economic, liquids opportunities within our existing portfolio. Because we've always valued a liquids to gas balance, we already have a vast inventory of liquids opportunities, including the Canadian oil sands, the Permian Basin, the Barnett Shale, the Cana-Woodford Shale and the Granite Wash. In addition, we continue to replenish and build upon that inventory with our new ventures activities. In 2011, we're allocating well over 90% of our upstream capital towards oil and liquids-rich opportunities. This will enable us to grow our year-over-year oil and natural gas liquids production at a rate in the high teens. And inevitably at some point in the future, gas prices will recover and incentivize the drilling of dry gas place. Since the vast majority of our properties are held by production, we can easily maintain our dry gas positions in the option value they represent. In the meantime, we'll continue to allocate our capital to oil and liquids-rich growth projects to generate strong rates of return in the current environment. This in summary, we remain fully committed to optimizing our growth on a per-share basis adjusted for debt. And in order to achieve that goal, we remain keenly focused on exercising capital discipline, maximizing our full cycle margins and maintaining a high degree of financial strength and flexibility. So with that overview, I'll turn the call over to Dave Hager for our review of our quarterly operating highlights. Dave?

Thanks, John, and good morning, everyone. Before I get started, I want to point out a couple of changes we're making this quarter to our operational disclosures. In this morning's earnings release, we have included a table that details production, operated rigs and wells drilled by key operating areas. The absence of this information from my remarks combined with our efforts to streamline the discussion of quarterly results should result in a more concise call and leave more time for your questions. So with that, let's look at our E&P program. The majority of our 2011 E&P program is focused on execution of our low-risk, repeatable development plays like the Barnett, the Cana and Jackfish. We also have upside potential with funds devoted to the evaluation and de-risking of various emerging plays in the Permian, the Rockies and in Canada. In addition, we have allocated capital to the acquisition of additional acreage and drilling of the initial wells and a handful of new opportunities that we have not previously disclosed. One of which I will identify today. Looking first in our thermal oil project in Eastern Alberta. We wrapped up the final commissioning activities for Jackfish 2 in the first quarter and expect to begin injecting steam in the next couple of weeks with first plant oil for later this year. Jackfish 2 production will continue ramping up throughout 2012. Our regulatory application for Jackfish 3 continues to progress through the review process. At Pike, our SAGD oil sands joint venture with BP, we began appraisal drilling in the fourth quarter and continued throughout most of the first quarter. In total, we drilled 135 stratigraphic core wells this winter and acquired some 60 square miles of 3D seismic data. Although additional seismic interpretation work will be done in the coming months, results from the strat drilling program were in line with our expectations. Our 2011 drilling efforts were concentrated around the north-central portion of our Pike acreage and confirmed sufficient resources for at least one 300 million barrel project. Ultimately, we expect Pike to yield 4 or 5 similar size projects. We hope to begin the regulatory approval process for the first phase of Pike in the first half of 2012. Planning is already underway for next winter's drilling strat program and seismic program aimed at further refining our view on additional Pike prospects. Our combined interest in the Jackfish and Pike projects represent estimated risk resource potential of 1.4 billion barrels net to Devon. The development of these projects is expected to drive our net SAGD production from the 3,000 barrels per day, we are currently producing to at least 150,000 barrels per day by 2020. This is based on the acreage we currently have in hand, without any additional acreage acquisitions. Moving now to the Bone Springs play in the Permian Basin, Devon has established a position, covering 185,000 net acres. We currently have 3 operated rigs running. Our initial activity has been focused in 2 primary areas of the play. We have been running 2 rigs targeting the first and second Bone Springs interval in Northern Eddy and Lea County in New Mexico. Our second focus area targets the third Bone Springs on the Texas side in Reeves and Loving Counties. In the first quarter, we have completed our second well targeting this third Bone Springs interval and the results were quite impressive. The 100% Devon owned Talladaga 65 #1H was brought online, with an average 30-day IP rate of more than 1,000 barrels of oil equivalent per day. We recently added another rig to the Texas side of the play in the second quarter, bringing the total number of rigs we have focused on the Bone Springs to 4. Also in the Permian Basin and the Avalon Shale Play, we're currently running 3 rigs. We are still in the early stages of evaluating our acreage position. However, based on drilling results to date, it appears, as you move east within the play, condensate yields improve. For example, the Cotton Draw Unit 134H in the eastern portion of the play was brought online late in the first quarter. For the 12 days, the well was flowing back before a shut in for installation of a pump, the well averaged 534 barrels of condensate per day and 2.5 million cubic feet of gas per day. Production history from similar wells in the area appears to support ultimate recoveries of between 400,000 and 500,000 barrels of oil equivalent. With approximately 60,000 net acres located in the eastern part of the play, Devon is well positioned in the liquids-rich portion of the play. Moving north to the Granite Wash play in the Texas panhandle, we continue to see solid results from our Cherokee and Granite Wash A wells. The Wright 151-2H completed in the Granite Wash A was brought online in the first quarter with a 30-day IP rate of nearly 2,800 oil equivalent barrels per day, including 690 barrels of oil and 704 barrels of NGLs. We also drilled our first Granite Wash B Well during the quarter. The Eden 11 4H was brought on line with a 30-day IP rate of 1,700 oil equivalent barrels per day, including 340 barrels of oil and 410 barrels of NGLs. In total, Devon brought 6 operated Granite Wash wells online during the first quarter. 30-day IP rates from these wells averaged 1,760 barrels of oil equivalent per day, including 250 barrels of oil and 490 barrels of natural gas liquids per day. We believe that we have about 700 risk undrilled locations in the Granite Wash. Moving now to the Cana-Woodford Shale in Western Oklahoma, where we are continuing to see outstanding results. First quarter production reached a record 162 million cubic feet equivalent per day. This puts us well on track to reach our year-end target of 250 million cubic feet equivalent per day. We continue to aggressively de-risk our position and secure the term acreage we acquired last year located northwest of the core area. Initial drilling results from this extension area indicate attractive rates of return, which should compete favorably for capital within our portfolio. In our Cana infill pilot program we initiated last year in the core area, production history from our 500-foot space wells continued to perform well. As a result, we plan to drill 3 additional infill pilot programs later this year. The additional production history gain from these infill wells should further support our position that 8 to 10 wells per section is the correct spacing in the core area. Shifting to the Barnett Shale field in North Texas, our initial plan calls for running 12 rigs throughout 2011. However, as we enter the year, we had 13 rigs running in the Barnett. Given the tightness in the market, we decided to retain the 13th rig with a thought that we could probably need it in the Granite Wash as we de-risk that position. Given our recent success in the Granite Wash program, we will be moving that rig up there during the second quarter. And in addition, we picked up a 14th rig in the Barnett during late March. This is a high-efficiency rig being dropped by another company and we secured it to high grade our fleet. We will drop a lower efficiency rig, bringing our operated Barnett rig count back to 12 where we expect to keep it for the remainder of the year. Our net production continue to grow during the first quarter, and we exited the quarter producing over 1.2 Bcf equivalent per day, including 43,000 barrels of NGLs and condensate per day. Remarkably, our Barnett production has climbed in spite of reducing our rig count over the last 12 months. Our deep inventory of undrilled locations is some of the best parts of the play has allowed us to high grade our drilling program which, in turn, has yielded higher IP rates. In the first quarter, we brought 103 Barnett wells online with average 30-day IP rates of approximately 2.7 million cubic feet equivalent per day, including an average of 137 barrels of liquids per day. We also continue to improve results with pad drilling and other drilling efficiencies in the Barnett. By further reducing the number of days it takes to drill a well, we are able to mitigate rising service cost. In 2010, we averaged 13.3 days from spud to rig release. While so far in 2011, we're averaging just 12.6 days. On the exploration front, we continue to actively evaluate the oil and liquids potential on our acreage within our portfolio that spans numerous play types across multiple basins in the U.S. and Canada. In Canada, for instance, at our Viking light oil play in Saskatchewan, we drilled 3 wells in the first quarter. We are still in the early stages of evaluating our acreage position, but believe we could have between 1,000 and 2,000 Viking drilling locations. And in addition, we had 3 Cardium wells drilled at the end of the quarter in the Deep Basin of Alberta. Of our nearly 600,000 net acres in the Deep Basin, we believe at least 80,000 acres is perspective for the Cardium. We expect to complete both the Viking and Cardium wells in the second quarter. In the Rocky Mountains, our exploration efforts are focused on evaluating several Cretaceous oil objectives, including the Niobrara and Parkman on our 220,000 net acres in the Powder River Basin. We have 3 rigs currently running, with 2 drilling Parkman wells and one drilling for the Niobrara. In the first quarter, we drilled 4 Parkman wells which are all scheduled to be completed in the second quarter. We will keep you updated on our progress as we move forward. We have been telling you for sometime now about our goal to identify and establish large acreage positions in highly economic plays at reasonable prices. We have continued building these new venture positions and now have roughly 850,000 net acres and a handful of new plays, primarily targeting oil and liquid rich gas. While we are still actively leasing in several of these plays, we're not ready to discuss them all, we have largely secured our position in one new area that I will tell you about today. The Tuscaloosa Shale is located along Louisiana and Mississippi border. This is a Cretaceous age formation that is stratigraphically equivalent to the Eagle Ford Shale. It is approximately 200 to 400 feet thick, at depths of 11,000 to 14,000 feet across our acreage position. Oil production has been established, up dip in the play from the Tuscaloosa Shale. We plan to utilize horizontal drilling and fracture simulation to enhance the productivity of the reservoir in both the oil and liquids-rich portion of the play. We have leased or have committed under contract approximately 250,000 prospective net acres at an average cost of $180 per acre. We plan to drill our first 2 horizontal wells in the play this year. In total, first quarter capital expenditures for North American onshore exploration and development totaled $1.5 billion. Our 2011 capital budget is front-end loaded due to our winter drilling program in Canada and because most of our 2011 SAGD expenditures occurred early in the year. However, the $1.5 billion of upstream capital spent in the first quarter is about $100 million over our internal budget. Two areas drove most of this overspent. First, activity levels on properties operated by others exceeded the level we expected; and second, some smaller working interest owners and properties operated by Devon were unable to fund their share of capital, thereby allowing us to step in for a greater interest in these projects. While this will likely push us to the higher end of the range we provided for capital expenditures, it should also result in greater production later in the year and into 2012. So in summary, our key developed projects are delivering excellent results. Accordingly, we are highly confident of meeting our production growth targets. This growth is being driven by strong, double-digit liquids growth. And we are making substantial progress on the exploration front. With that, I'll turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

Thanks, Dave. Good morning, everyone. Before we move into the financial review of the quarter, I want to remind everyone, my comments will be focused on results from continuing operations or in other words, our North American Onshore business. For those of you interested in a more detailed review of our discontinued operations, we have provided supplemental tables in our news release. As John mentioned earlier, first quarter results were very strong and most income statement in key operating metrics were right in line with our expectations. For today's call, I will only review those items that require additional commentary or are outside our forecasted guidance range. The first item I will cover is our production performance. We produced 56.6 million equivalent barrels from continuing operations or approximately 629,000 barrels per day. This exceeded the top end of our guidance range by roughly 4,000 barrels per day. First quarter production benefited from better than expected performance from key properties, including the Cana-Woodford and Barnett Shales. When compared to the first quarter of 2010, our North American Onshore production increased 7%. This growth was achieved in spite of production interruptions caused by severe winter weather in the first quarter of '11. The most significant portion of this year-over-year growth came from U.S. oil and NGL production. Gains in the Cana, Permian Basin and Barnett drove this growth. Looking ahead to the second quarter of 2011, we anticipate continued strong growth. The midpoint of our guidance range of 645,000 to 655,000 barrels per day implies an increase in sequential quarter production nearly 3.5%. This growth is driven by the same areas that drove our first quarter results, the Cana, Permian Basin and Barnett. Given our performance thus far, we feel very comfortable with our forecast for liquids production growth in the high teens, driving overall top line production growth of 6% to 8% in 2011. While we are clearly on track to come in at the high end of this range, we are not modifying our full year guidance at this time. On the pricing front, the major story for the quarter was the robust oil price environment. Geopolitical tensions and strong worldwide demand resulted in WTI oil price surpassing $100 a barrel in early March. The strength in oil prices provided a good opportunity to hedge oil at historically attractive levels. As we have discussed in the past, we try to protect the price on roughly half of our expected production of both oil and natural gas. Our objective is to strike an appropriate balance between managing risk and retaining exposure to upside volatility. For the full year of 2012, we now have 76,000 barrels per day, hedged through various swap and causes collar contracts. Of this amount, 22,000 barrels per day were swapped at a weighted average price of $107 per barrel, and the remaining position utilizes collars with a weighted average ceiling of $126 and a floor of $86. Natural gas price volatility has also provided an opportunity to boost our hedge position. For the second quarter of this year, we added 550 million cubic feet per day of hedges, increasing our total hedged production for the second quarter to roughly 1.3 Bcf per day. This position covers approximately 50% of our expected natural gas production in the second quarter, with a weighted average protected price of $4.95. We have also begun adding gas hedges for next year. For the full year of 2012, we now have swap and collar contracts covering nearly 400 million cubic feet per day, with a weighted average protected price of $4.93 per Mcf. We will post an updated hedging schedule on our website today that provides a more detailed view of our 2011 and '12 hedge positions. Looking now to expenses. Once again, the repositioned company did a very good job controlling costs. Expenses in most categories were generally in line with expectations during the first quarter. In aggregate, our pretax cash cost for the quarter came in at $13.12 per Boe and were about $0.10 per barrel lower than the first quarter of 2010. As E&P and service companies alike have disclosed, we are in a rising service and supply cost environment. However, our focus on cost control, combined with the efficiencies realized through our repositioning have more than offset both industry inflation and the negative impact of the strengthening Canadian dollar. Shifting to income taxes. As Vince mentioned earlier, our overall tax rate was 34% of adjusted pretax earnings or about 4 percentage points over the midpoint of our guidance. Current taxes were 2%, while deferred taxes were 32% of adjusted pretax earnings. This is indicative of what we expect for tax rates on adjusted earnings for the full year. A reconciliation of tax on both GAAP and adjusted earnings is available in today's release. Looking ahead to the remainder of the year, we anticipate continued upward pressure on cost. However, we remain comfortable with the full year expense forecasts provided in our February 8-K. Regardless of industry conditions, we are confident that Devon is well positioned to continue generating full cycle margins that are among the best of our peer group. Also, from a balance sheet perspective, Devon remains exceptionally strong. At March 31, we exited the quarter with $3.4 billion in cash and short-term investments and total debt of only $6.8 billion. This, of course, is before the $3.2 billion we will receive upon the close of the sale of Brazil. This significant financial strength provides us the flexibility to consistently invest in our business based on our long-term outlook regardless of the near-term macro economic backdrop. We believe that we are extremely well positioned to compete effectively, delivering highly competitive growth in cash flow and production per debt adjusted share. At this point, I'll turn the call back over to Vince for the Q&A.

Operator, we are ready for the first question.

[Operator Instructions] Your first question comes from the line of David Heikkinen from Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Looking at your second quarter volumes, how important is the Cana plant coming online? And kind of what is that impact as far as timing and kind of quarter-over-quarter growth?

The Cana plant is already online. This is Dave, David. It came on in the fourth quarter, so that's really... David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So you don't have any constraints in the Cana. Basically you're -- you're basically able to continue to run your rig count up and that is unconstrained?

That's true. Probably the biggest driver for the second quarter volume is we have a program in the Barnett where we drilled from a couple of pads underneath like Benbrook. And we have 20 wells on the first of those pads that we're been bringing on, and we've already ramped that up here in the second quarter to $47 million a day. And that all happened after the end of the first quarter. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And thinking about capacity with the big wells and the Granite Wash as well kind of 1,700 barrels of oil equivalent with a high NGL yield. Can you talk through -- to set a risk location, now 700 risk Granite Wash locations?

Yes, that's a gross risk location number, Dave. This is Vince. And our average working interest is somewhere around 50%. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: So still thinking around 350 total locations on a net basis?

Correct. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. No changes to that. And then on the other side, thinking about the new plays and kind of new ventures, can you talk about expectations for Viking activity levels, which you have 1,000 or 2,000 locations. What are the constraints there, and could that become a kind of Sprayberry-like development?

Well, it has the potential to be significant. We're going to drill probably on the order of 15 or so wells in the Viking this year. I think the primary variable there, David, is not so much as the reservoir there. We're pretty confident we have the reservoir there for somewhere between 1,000 and 2,000 locations. The primary variable is can we get the cost down so that it competes effectively within our portfolio. We have a pretty high grade of portfolio and that's why we're going to start drilling out there and see if we can achieve the efficiencies we think we can to make it economic within our portfolio. We're estimating recovery about 50,000 barrels per well and drilling completing cost of around $1.2 million, $1.3 million. So we need to get to that to make it compete well. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: That's my question.

And David, you will recall as well that as you're well aware, most of the line in Canada is leased from the Crown but this is fee acreage that we have, so that also helps to improve the economics.

And then no royalties, is that right?

And no royalties, yes. We own the mineral interest in that 900,000 acres. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: I have covered more than two questions.

Your next question comes from the line of Dave Kistler from Simmons and Company. David Kistler - Simmons & Company International: Real quickly on the Bone Springs just a little maybe additional color in previous calls, you talked about the EURs trending up to the high end of the range on the first and second Bone Springs. Can you give us any color on does that continue to be the case, or are you going to be adjusting those EURs higher? And then put that in perspective to the third Bone Springs wells that you've drilled, that would be fantastic.

Hi, Dave. We are very, very pleased with the results that we're achieving both in the first and second Bone Springs, as well as the third Bone Springs. And at this point, we're still wanting to get a little bit more production history before we revise our numbers upward. But I can tell you that the results we've seen so far have been very encouraging. We're certainly confident we're at the upper end of the range that we said previously. And hopefully, with a little more production history, we're going to revise those up further. David Kistler - Simmons & Company International: And is there a big delineation between cost on the first and second versus the third Bone Springs?

Yes, the third Bone Spring is significantly deeper. So those wells are quite a bit more expensive to drill, yes. And the cost range from the first and second probably around 4.5 to 5 drilled and completed and up to 6.5 to 7.5 on this third Bone Springs. David Kistler - Simmons & Company International: Okay, great. And one last just a quick follow-up. When you talk about the production growth, you highlighted the drilling efficiencies and high grading in the Barnett as you just mentioned, the EURs and the Bone Springs. Are those the primary drivers to the production growth, and are we seeing it across the whole portfolio or is it really limited to those 2 areas?

Well, we're seeing production growth across several areas within the portfolio, particularly on the oil and natural gas liquids side. But when you look at overall portfolio, just to give you an idea, just on the oil and natural gas liquids which is where our primary growth is, we anticipate growing volumes on the order of about 12 million barrels or so this year. Then about 6 million of that would be on the oil side in the Permian and Jackfish area. And then another 6 million or so primarily in natural gas liquids in Cana, Barnett and Granite Wash.

And one of the really high growth areas of course is the Cana. We got tremendous resorts that near about 40 miles outside of Oklahoma City. And when you look at our production history, I think we're, if my memory serves me correctly, we're at about 113 million a day in the fourth quarter of 2010. And by the end of this year, that's going to ramp up to 250 million a day, and our liquids volumes are going to go from 4,000 or so or probably up 4,000 or 5,000, up to about 14,000 at the end of 2011. So that's a significant increase.

Your next question from the line of Scott Hanold from RBC Capital Markets.

I was wondering could you provide a little bit more color on what you're seeing in the Tuscaloosa Shale? I mean, did you have some like vertical well penetrations that you like to see? And I apologize, I missed some of your color that you did provide around it. Did you phase now just to another shale play in the area?

Well, yes, let me just give you a few of the things that we like about the Tuscaloosa Shale. And having said that, this is a frontier place, so I do want to mischaracterize it as something else because -- and frankly, we have been leading the industry by taking our position here. So it is a frontier play. But let me tell you some of the things that we do like about the play that give us reason for encouragement. It is the stratigraphic equivalent to the Eagle Ford Shale. It is deeper than Eagle Ford Shale about 11,000 to 14,000 foot depth, but it is a stratigraphic equivalent to it. There has been oil production established up dip in the Tuscaloosa Shale also. There have been some vertical wells that have been drilled in there that indicates that you're getting for a shale-type play, that has good porosity and permeability. We're also seeing some carbonates in there, which indicate that maybe somewhat brittle and able to be fractured. We've seen IPs on the vertical wells up to 300 barrels per day. They were just about -- just a very small number of horizontal wells have been drilled a couple or 3 years ago, and they were of limited horizontal link on the order of 1,500 to 2,000 foot with only 3 stages. But they tested up to 500 barrels per day from these very limited and minimally frac-ed wells. So all of those give us reasons for encouragement. Now having said that, it's very early on, and we're going to start drilling some horizontal wells, we need to get more data on rock frac-ability. And there are some sands below that are wet, we need to stay away from those. We need to get more information on the phase, oil and natural gas because just aren't that many wells. We know exactly who are on the play, the boundaries between those are. So there are some risks associated with it. I don't want to mislead you. But there are some encouraging qualities to establish a 250,000-acre position for less than $50 million, that's kind of thing we're successful. We can create an awful lot of value.

Okay. Great, great. And you said, you're going to drill 2 horizontal wells there this year, is that correct?

Yes, we're going to have a rig out there here in the second quarter.

Okay. And then for my follow-up, on the proceeds you're going to receive from the Brazilian sale, when that occurred, what is the status of those funds? Are you going to able to repatriate that money, or is there going to -- should we think about that taking a hair cut to that?

This is Jeff Agosta. When we gave you an estimate of $8 billion in after-tax proceeds from our completed sales, that did contemplate a large portion of tax paid on repatriation. The $3.2 billion of proceeds from Brazil specifically is that deal was structured as tax-free as long as those funds remain outside the United States. So we will leave those outside of the United States until we get some more clarity around any potential change in U.S. tax law that would encourage a repatriation of funds to the United States.

Okay. And so -- I mean, is the thought process right now you don't need that cash, and so it could be just serving some short-term investment out there, is that right?

That's correct. We would just leave it and park it as a short-term investment or to the extent that we had incremental opportunities in Canada, we would be putting that money to work in Canada.

Okay. So that can be shifted to Canada tax?

Yes, it can be.

Your next question comes from the line of Mark Gilman with The Benchmark Company.

Dave, the Tuscaloosa Shale play, I was wondering, is this at all equivalent to the play that Mainland Resources has been looking at in that same area?

I'm not familiar with that. It's possible, Mark. I don't -- I heard that name. I can tell you there hasn't been a lot of other leasing activity to date, which is one of the reasons we're excited we're able to get in there for such and get a strong position for such a low cost.

Well, let me just go further, if I could. Is there any Haynesville potential in this play that you've identified, perhaps?

We haven't identified any, no.

No? Just one other by way of not related follow-up. From a royalty ring fence perspective, can you clarify whether Jackfish 2, 3 and potentially Pike are or are not in one ring fence for royalty purposes up there?

Mark, it's John. We have made an application and believe that the 3 Jackfish projects will be part of -- will be considered as one project or have a ring fence for royalty purposes. The Pike development will likely be a separate project.

But John, you have not gotten approval with that submission?

We have not at this point had confirmation of that, but it seems to meet all of the requirements. And so we expect that, that will get that kind of treatment, Mark.

Your next question comes from the line of David Tameron from Wells Fargo.

Back to Tuscaloosa, how many vertical wells have been drilled in the area? How much data do you have that you're looking at?

It's just a handful of vertical wells. I don't have an exact number of it. And about 3 or so horizontal wells were drilled about 3 years ago I think, 3 or 4.

Okay. And again, you said you're going to start drilling second quarter and then update us late this year, first part next year type of thing?

Yes. Just so you know, I mean, the Tuscaloosa Shale, I worked at this play as a geophysicist 25 years ago by the way, not for the shale but there are some sands just beneath there that everybody was drilling for 25 years ago. There's a lot of wells have gone through the Tuscaloosa Shale, but the wells I'm talking about are ones that are actually completed in the Tuscaloosa Shale.

Okay, okay. And then on CapEx budget. I heard the comment about $100 million ahead right now at the end of 1Q on the development side. It kind of sounded like CapEx was headed higher for the full year. I mean, should we think about it as $400 million higher? Should we -- can you give us some type of...

Yes, this is Vince. I would not assume that we're going to be $400 million over for the full year. Of course, the capital budget is fluid with changes in the macro environment and drilling results. And clearly, these were unanticipated nonparticipations by working interest owners and a high level of OBO activity. But I don't think you can extrapolate that, not over for the full year. So we think this likely pushes as high in the range. We had a pretty broad range, but we don't have any reason to believe we're going to be out of range at this point.

Okay. No, that's what I'm looking for. Good.

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

On the Permian and the Delaware Basin, between the Bone Spring 3 zones and the Avalon Shale, can you refresh us on your thoughts as to whether you are seeing commercial overlap of any of these zones and whether that's something that you have tested?

Yes, there are -- the Bone Springs interval does tend to overlap somewhat with the Eastern portion of the Avalon. So yes, they are the same acreage, you can see prospectively on both of it in some of the areas, yes.

And Brian, you recall there are also some additional horizons that overlap. They're not all directly overlap as Dave said, but portions of it overlap in some of the other places in that area as well like the Wolfcamp Shale and the UPS and some other zones that are prospective and that we're going to be taking a look at throughout the year as well.

And so I guess how many prospective zones do you think you would have on your average Delaware acreage?

Probably somewhere 3 to 5, I would say something like that. Over a lot of the acreage we see, the Avalon -- and even within the Avalon, there are different benches in the Avalon. So it's not all -- it's not just a single perspective zone there. And then over most of the Avalon, you have both, as John said, the Wolfcamp and the upper Penn shale is prospective. Then over a portion of the acreage, same acreage is where the Bone Spring is prospective. I also have Delaware potential out there as well, if you haven't gone into those. There are several different zones.

In the Barnett Shale, you mentioned that during your comments that the production is surprising here to the upside despite the lower rig count. Is that just the higher IPs that you're seeing from the wells you're choosing to drill that's keeping production higher? Or are you seeing anything different in the underlying decline rate from past legacy wells?

I wouldn't say we're seeing anything significantly different as primarily the higher IPs, although I can tell you that just about every year for the past 5 or 6 years, we've had positive reserve revisions in the Barnett as we see showered declines and we had booked.

Your next question comes from the line of Mark Polak from Scotia Capital.

First question on Jackfish 3, just curious if you can give an update on how the regulatory process is going and do you still think there's a chance of starting construction there later this year?

I think Mark, the process is going about as expected. We filed the application in the Fall. We're going through the regular part of the process. We don't have any reason to think that it's not on track on the timetable that we expected. So if we were to get that approval optimistically, we thought around the end of the year probably more likely at the beginning of 2012 sometime and we'll get in there and put a shovel in the ground as soon as we can.

That's great. And you mentioned in the Barnett taking -- production drilling despite taking the rig count down, just curious what the plans are going forward. Are you looking at further rig count reductions there, or what the development plans are in Barnett?

Well, we're going to stay, as I said, we're going to stay -- we were temporarily at 14 rigs we've showed up in the new table we've put in the earnings release. But the reality is, we'll be back to 12 here fairly soon and stay there for the rest of the year, and we're very comfortable. But when we look at allocating capital, we look at it on a company-wide basis. So we'll take a look later on this year and see where it looks like the best decision is for -- and get the most out of our capital for next year. But we're certainly extremely pleased with the results of being able to actually grow production this year versus last year in the Barnett with 12 rigs and throw off after CapEx of over $400 million. It's outstanding results.

And Mark, you recall that we talked about the fact that we got 7,000 risk locations in the Barnett, about 2,500 to 3,000 of them are probably in the liquids-rich area. So we're really focusing on drilling in the liquids-rich areas. And frankly, what we're trying to do is optimize our plant capacity and our throughput. We've got the biggest plant in that area, and we're drilling in those liquids-rich areas having regard to what our capacity is.

That makes sense.

Your next question comes from the line of Gilbert Van Voorden from Wells Fargo.

I have a question on the hedging. I must missed this on the natural gas and the oil. How much of your production in 2011 and '12 is hedged in gas and in oil, and what is the average price?

We'll be filing or posting the details to our website later today, but we gave a summary in the call today. Let's see, that was -- go ahead and pick that up, if you know...

I think we're about 50% hedged on natural gas in the second quarter of this year, and we're about 1/3 hedged on natural gas for the second half of the year. And those protected prices are in the high $4.90s, so close to $5 in Mcf. We're about -- on natural gas for 2012, we're only about $400 million a day hedged out of about -- so we're about 17% to 18% hedged for 2012, natural gas at a protected price of about $4.95.

Might add that we're actively in the market right now.

Correct. And then on crude oil, we're about 50% hedged for next year. We've got about 76,000 barrels per day hedged next year. 22,000 barrels of which is swapped at about $107 a barrel with collars on the remainder, protecting a floor price of $86 a barrel with participation in the upside up to $126 per barrel.

I see. Now just a follow-up on that. On the natural gas, which I am probably the only guy that's bullish on, I've been bullish for almost a year and not right so far, but should it go through your collar? Would you remove the collar or just stay where you are?

This is Darryl Smette. Historically, we'd just left them where they are because gas prices tend to be very volatile as you know.

Right, right.

And we would hate to get out of a position that our long-term forecast suggests that we're going to be in that type of price range. So our historical pattern, I don't think we would change from that. We would leave our collared positions on.

I see.

Your next question comes from the line of Ross Payne with Wells Fargo.

Jeff, quick question. Do you a target debt to cap for the company given all the cash coming in with these asset sales?

No, we don't have a target debt to cap. We don't manage our balance sheet around that particular metric. What we do try and maintain is maximum financial flexibility and a strong investment grade credit rating. We have our credit ratings right now are Baa1 and BBB+ by Moody's and S&P, Fitch, respectively. And that's really the rating that we target for and manage our balance sheet accordingly.

Okay. You've obviously been doing some asset -- I mean, some acreage purchases. Can you talk just briefly of your appetite for any kind of acquisitions going forward here?

Ross, we got a pretty big portfolio now and a portfolio that we really like. So whereas it's the right thing for us to get out there and continue in some of these new venture areas and some of these first mover position like Dave said, where we can put acreage together for a few hundred bucks an acre. We really don't have an appetite for acquisitions because it's not going to make us -- in most cases, it's not going to be accretive to our asset base at today's prices. If you look at it, most companies even on the gas side are still being discounted at a slightly higher price than the strips. So that's not likely. We will continue to build our positions though on some of these new venture areas where it makes sense.

Your next question comes from the line of John Herrlin from Societie Generale.

Some quick ones for you, Dave. With the Tuscaloosa, have any idea what the completed well costs will run?

Well, it's pretty early on here. And obviously, the first well are going to be more science well, as I said, where we're going to do a lot more we're not going to have the efficiencies that we think we'll have in later wells. We think probably, eventually that somewhere around $12 million range is somewhere where we will be looking at drilling and complete.

Okay. With that formation, do you have sense of what the TOCs are?

TOCs run around 3% or 4%.

Okay. Last one for me. You're having success in Cherokee, the Parkman, Bone Springs. Are you changing your completion techniques at all? Are you like the horizontal wells doing more frac stages? What are you doing differently today versus, say, last quarter?

No significant changes, I would say, in the Cherokee. What we're doing there or in any of these really, I wouldn't say, no. We've had pretty good success on the completion of those and we may be adding a couple of frac stages, but there's nothing that's material different that one quarter versus the other, John.

Your next question comes from the line of Harry Mateer from Barclays Capital.

This is for Jeff. My question was going to be whether you might use some of the Brazil proceeds to pay down debt. But given that it sounds like you won't be repatriating any time soon, can you just give us a sense on how the debt line is going to trend throughout the year?

Well, our short-term borrowings I would project as we continue to execute on our share repurchase program, our short-term borrowings will continue to escalate. We do have that $1.75 billion bond that matures at the end of September this year that we will be looking at what portion of that we might refinance versus pulling the short-term borrowings. And so I would expect that our headline debt number would continue to increase as long as we leave those proceeds offshore.

And your intent is to keep that short-term dept in CP, or do you think you might actually term it out down the road?

It'll all depend on the capital markets and the cost of short-term funds. I mean, right now, we're funding in the short-term market at very attractive rates, sub-30 basis points. So that's pretty compelling.

Your next question comes from the line of Eric Hagen with Lazard Capital Markets.

Dave, a quick follow-up on the Parkman. Just wondering if you can characterize that the same way you did the Tuscaloosa. And also, has there been any industry activity around your acreage, any horizontal results to date?

Yes, the Parkman, there isn't as much activity going on around there. We have seen a couple of plays historically, there've been made in the Parkman, El Paso, made a play 2 or 3 years ago. That was not too far away from it in a similar type play. The Parkman is really it's a different place. The Parkman itself is more of your stratigraphic trap. It is actually a sand and you're just looking at a stratigraphic trap typically 1 to 2 miles wide and perhaps many miles long. And then what you're really looking is with many of these, whether it's somewhat tighter sands though that are more easily developed and much more economically developed with horizontal drilling and hydraulic fracturing. And so that's what we're really doing there is taking advantage in these tighter sands of new technology and producing the increase in the ultimate recoveries of these wells through hydraulic fracturing and horizontal drilling.

Okay. One just follow-up on that then. So would the Parkman then be prospective across the whole, I think, it was 220,000 acres or will it be just sort of more geographically limited? Any...

Well, let me give you a perspective here. We gave it -- and these numbers change day-to-day as our geologists are working here. But if you say that right now, that our -- we give our Rockies exploration program maybe 200 million barrels of risk potential, I'd say that the Parkman is not the biggest one, and maybe -- and we may change our minds as we drill more well. There's probably more on the order of 20 million, 30 million barrels of that potential. The biggest potential out there we think is the Niobrara. And we're drilling our first Niobrara well right now. We think that has 100 million barrel plus risk potential in the Powder River. So it's a nice play, but I think the bigger potential probably is Niobrara and also in the Maori.

Okay. Operator, I'm showing the top of the hour. We're going to cut it off at this point. As usual, the Investor Relations staff will be around the rest of the day for any questions we didn't get to. Thank you for participating in today's call.