Devon Energy Corporation (DVN) Q1 2012 Earnings Report, Transcript and Summary

Welcome to Devon Energy's First Quarter 2012 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 Communications and Investor Relations. Sir, you may begin.

Thank you, operator, and welcome, everybody, to today's first quarter 2012 earnings call and webcast. Today's call will follow the usual format. I'll start with a few preliminary items and then turn the call over to our President and CEO, John Richels for his overview. 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. We'll conclude with a Q&A period, and as usual, we'll ask you to keep your questions limited to one and one follow-up, and we'll hold the call to about an hour. Also with us today is Larry Nichols, our Executive Chairman, as well as other members of Devon's senior management team to help out with the Q&A session. A replay of this call will be available today later on through a link on our homepage. As usual, our call will contain some forward-looking estimates. And we will be refining some of those in our call today, but we are not planning to issue a new 8-K. We will, however, post those changes to the guidance page of our website. To find that, just click on the Guidance link found in the Investor Relations portion of the Devon website. Please note that all references today to our plans, forecast, expectations and estimates are forward-looking statements under U.S. securities law. And while we always strive to give you the very best information possible, there are many factors that could cause our actual results to differ from those estimates. We urge you to review the discussion of risk factors and uncertainties that we provide in our SEC Form 10-K filing, provided that is. Also in today's call, we'll reference certain non-GAAP performance measures. When we use these measures, we're required to provide related disclosures. Those are also available on the Devon website. The First Call mean estimate for Devon's earnings for the first quarter was $1.43 per share. However, at the midpoint of the guidance we provided, you would've expected our first quarter earnings to come in at $1.35 a share or $0.08 below The Street estimates. However, our actual first quarter non-GAAP results came in at $1.05 per share or $0.30 below our guidance. This was most almost entirely due to unusually wide differentials on Canadian oil and U.S. NGLs. Jeff will cover both of these, as well as our expected future price differentials in detail later in the call. With those items out of the way, I'll turn the call over to John.

Thank you, Vince, and good morning, everyone. Although, as Vince mentioned, wide differentials had a significant negative impact on earnings, we delivered another very solid quarter from an operational perspective. Our North American onshore production reached an all-time record, averaging 694,000 equivalent barrels per day in the first quarter. This represents a 10% increase over the year-ago quarter and that was led by a 26% growth in oil production. On a sequential quarter basis, a 7% increase in oil and NGLs production more than offset a 1% decrease in natural gas production. We continue to bolster our future oil potential by assembling significant acreage positions in additional new oil plays, and we continue to do a very good job of controlling costs. Pretax costs -- or pretax cash costs per unit of production increased only 1% from the last quarter of 2011. And even in an environment of weak commodity prices, we delivered net earnings of $393 million and cash flow of $1.4 billion. Devon's financial position remains rock solid. We ended the quarter with the $7.1 billion of cash on hand, and we continue to have one of the lowest debt-to-cap ratios in the industry. This financial strength is especially important given current natural gas prices. The economics of drilling dry gas wells are unattractive, and reduced cash flow from lower pricing makes sustaining investment and higher-margin oil- and liquids-rich gas more difficult for many. Our financial strength allows us to continue to fund a robust E&P capital program directed entirely towards oil- and liquids-rich opportunities. The economics of these projects are enhanced by low royalties, reasonable operating costs and by our midstream operations. In aggregate, our 2012 drilling activity will deliver oil production growth in excess of 20% and double-digit growth in NGLs. And more importantly, the projects driving this growth are delivering very attractive rates of return. Even if the current pricing environment were to persist indefinitely, our existing base of oil- and liquids-rich projects provides us many years of profitable growth. To put this into perspective, roughly half of our 16.2 billion barrels of risked resource is oil and NGLs, with crude oil accounting for nearly 5 billion barrels of this total resource. So our resource base provides the ability to shift investment to the most lucrative opportunities depending on market conditions. Our solid financial position is also allowing us to aggressively build up the light oil portion of our inventory. We've been very successful in adding significant oil-focused acreage positions at very attractive entry cost. Our biggest addition is our recently unveiled Cline Shale oil play to the 500,000 net acre position that we've assembled in the Permian Basin and that was assembled at very reasonable cost. We're also building a large, concentrated position in another oil prospect that's not yet ripe for disclosure. As of today, we have commitments for or have closed on 250,000 net acres in this undisclosed position, with an ultimate target of about 500,000 net acres. Our new ventures unit is well-staffed, and it's adequately funded to continually evaluate greenfield opportunities across North America, as well as to identify untapped potential on our existing acreage base. As 2012 progresses, you'll see more of the fruits of these efforts. Due to the significant success that we're enjoying in identifying and capturing resource potential, we are open to taking on partners to help us develop our new exploration plays. While we could easily pursue these opportunities on our own, bringing in a partner enhances our overall risk-reward profile. As evidenced by our $2.5 billion Sinopec transaction, joint ventures offer the opportunity to accelerate activity, improve capital efficiency and mitigate risk. And most importantly, this type of transaction supports our primary strategic objective of maximizing cash flow per debt adjusted share. The combination of our financial strength, our low-risk development inventory and our growing new ventures portfolio underpin our oil production growth. As a result, in our view, Devon provides a differentiated opportunity for investors in the E&P space. So with that, I'll turn the call over to Dave Hager for a more detailed review of our operating highlights. Dave?

Thanks, John, and good morning, everyone. Given the in-depth update we provided just a month ago at our Analyst Day, I'll keep my comments fairly brief this morning. Let's begin with a quick recap of first quarter capital expenditures. E&P capital for the first quarter was $1.6 billion, including undeveloped acreage acquisitions. Operationally, we're off to an outstanding start this year with record production from each of our 4 cornerstone developed product areas: Jackfish, the Permian Basin, the Barnett and Cana. We also continue to move forward with evaluating and derisking the upside potential in our various emerging and new ventures plays. Now let's take a closer look at some of the first quarter highlights. Starting with our thermal oil projects in Eastern Alberta, aggregate production from our 2 producing Jackfish projects averaged a record 46,000 barrels per day, net of royalties, in the first quarter. Jackfish 1 accounted for 30,000 barrels per day as its total, and continued its trend of excellent plant reliability and efficiency. At Jackfish 2, production continues to ramp up, and we're currently producing more than 21,000 barrels per day after royalties. We continue to expect to reach facility capacity at Jackfish 2 somewhere around year end. Jackfish 3 construction is also progressing well, with roughly 30% of the project complete, putting us on track for a late 2014 start-up. At Pike, we wrapped-up our winter drilling program during the first quarter. We drilled 131 stratigraphic core wells and acquired some 50 square miles of 3D seismic. Although we're still working with our partner to finalize the Pike 1 development plan, we expect to file an application for regulatory approval for the first phase of Pike late this summer for a project of up to 105,000 barrels per day of production. We operate Pike with a 50% working interest. Between Jackfish and Pike, we expect these projects to drive Devon's net thermal oil production to more than 150,000 barrels per day by the end of the decade. Moving now to Permian Basin. Our total net production averaged a record 56,300 barrels of oil equivalent per day in the first quarter, up 28% over the first quarter of 2011. Permian oil production grew 32% over the same period last year, and light oil now accounts for nearly 60% of our total volumes. Our Permian oil play is currently represents some of the highest return opportunities in our portfolio. Since year-end, we have continued to ramp up activity with the addition of 5 new rigs. We currently have a total of 21 operated rigs running in the basin, and expect to add additional rigs by year-end. Looking at a couple of Permian plays in a bit more detail. First, in the Bone Spring play, we continue to see outstanding results from our Bone Spring horizontal program in both New Mexico and Texas. In the first quarter, we completed 16 Bone Spring wells with an average 30-day IP rates of 580 barrels of oil equivalent per day. Our actual results in this play continue to outperform our analog well model. In the Wolfcamp Shale in the southern Midland Basin, we're continuing to fine-tune our drilling and completion techniques. We brought 2 Wolfcamp horizontal wells online in the first quarter, with 30-day average IP rates of 440 barrels of oil equivalent per day. Perhaps even more exciting is the result of a Wolfcamp horizontal well we drilled on our Wolfberry acreage in Ector County. This well is located some 80 miles to the Northwest of the southern Midland Basin, where the Wolfcamp play has been heating up. After 20 days of production, the Everett [ph] 17H is producing about 400 barrels of oil equivalent per day. While additional mapping and drilling is needed to better characterize the resource potential, our well, combined with another recent industry well in the area, suggests the horizontal Wolfcamp Shale play could extend to the Northwest. This would significantly increase our resource potential in the play. As we mentioned during our recent Analyst Day, there are many uncharacterized zones underlying our Permian acreage, and this is one example. We will keep you updated as we learn more. During our recent Analyst Day presentation, we also unveiled a large position that we have established in the Cline Shale on the Eastern flank of the Midland Basin. We are currently drilling a Cline well in Sterling County, the first of 15 wells we have planned for this year to assess our potential in the play. The depth and breadth of our existing Permian position is driving our Permian production growth rate at a rate of more than 20% per year. In addition, we are continuing to supplement this position by aggressively pursuing new opportunities in the Permian. Moving now to the Cana-Woodford Shale in Western Oklahoma. In spite of a temporary third-party facility outage that reduced our first quarter production by about 4 million cubic feet equivalent per day, as well as a large increase in uncompleted wells due to pad drilling, Devon still achieved an all-time production record at Cana. First quarter 2012 production increased 67% over the year-ago quarter and 8% over the fourth quarter of 2012. First quarter Cana liquids production grew even more, up 80% over the year-ago quarter, to 3,500 barrels of oil and 9,500 barrels of natural gas liquids per day. Also of note at Cana, we recently finished drilling our first 10,000-foot lateral, and expect to begin a 20-stage completion on this well later this year. We are currently drilling a second long lateral well in Cana. These wells will cost on the order of 20% to 30% more than a typical Cana-Woodford well. However, we expect to see an increase in per-well recoveries in the 60% to 80% range, further enhancing our Cana economics. Shifting to the Barnett Shale field in North Texas. In the first quarter, we continue to achieve excellent results with pad drilling. We brought 25 wells online from our Lake Benbrook pad, with 30-day average IP rates of 4.9 million equivalent feet of production per day, including 330 barrels per day of natural gas liquids. This helped drive first quarter net production from the Barnett to a record 1.37 Bcf equivalent per day. This included 52,500 barrels of liquids per day, up 23% from first quarter 2011. Moving north to the Texas Panhandle. In the Granite Wash Play, we continue to see solid results from our Cherokee and Granite Wash wells. We brought 6 operated Granite Wash wells online during the first quarter. The 30-day IP rates from these wells averaged over 1,650 barrels of oil equivalent per day, including 220 barrels of oil and 470 barrels of natural gas liquids per day. On the exploration front, we recently closed a Sinopec JV and continue to move forward with the de-risking of the 5 plays involved. Given the recent in-depth update provided at our Analyst Day, we have very little today in the way of incremental information. However, I will briefly review the current status for each of these opportunities. In the Mississippian oil play, located in North Central Oklahoma where the partnership has assembled 230,000 net acres, we are encouraged with the results of our first well. The Matthews 1H had a 30-day IP rate of 590 oil equivalent barrels per day, and is among the best wells reported in the play to date. We currently have 2 rigs running and 2 wells completing. We expect to drill or participate in roughly 50 wells on this acreage by year-end. It including tests of additional formations. In our Rockies oil exploration, as we previously indicated, we're testing a number of objectives in the Powder River and DJ Basins. Our first well in the Turner formation had a 30-day IP rate of 433 barrels of oil equivalent per day. We're currently drilling wells, testing 2 additional formations, the Mowry in the Powder River Basin, and the Codell in the DJ Basin. In the Tuscaloosa Marine Shale, we drilled our first 2 wells in the southern portion of our acreage position. As discussed during our recent update, results of the first 2 wells were somewhat disappointing. We have since moved our 2 operated rigs north and have 2 wells currently drilling and a third well that is roughly halfway through completion operations. These 3 wells will be the first to test our northern acreage position. In Michigan, we are currently completing our first horizontal well in the A1 carbonate. We also just finished setting casing on our second well, the Wiley 1H, and we should begin completing that well in a couple of weeks. As we have previously indicated, the A1 is a highly pressurized zone with a significant fracture system, so understanding how these characteristics impact commerciality will be key going forward. And finally, in Ohio, Utica, we just completed our first horizontal well, the Eichelberger 1H in Ashland County. We are now beginning to flow the well back. In addition, we drilled a second well that's awaiting completion and are currently drilling our third well in the play. We should have all 3 wells online by the end of the second quarter. So in summary, our 2012 capital program is off to a great start. With record production in each of our 4 cornerstone development areas, we are poised to deliver outstanding liquids growth. We have a more than 20% growth in oil. We continue to see encouraging results from a number of our exploration plays, as well as efficiently capture new acreage positions that will provide the next leg of oil and liquids growth in the years ahead. With that, I'll 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 first quarter results. For today's call, I will limit my comments to those items that require additional commentary that are outside our forecasted guidance range. Starting with production. In the first quarter of 2012, our reported production totaled 63.1 million oil equivalent barrels or 694,000 BOE per day. This record result was at the high end of the forecasted range we provided in our fourth quarter call. As John said, this represented 10% growth rate over the first quarter of 2011, driven by a 26% increase in oil production. The Permian Basin, Jackfish, Cana-Woodford and Barnett Shale all delivered record production in the first quarter. Looking at the second quarter, we expect growth in the Permian Basin and Jackfish to boost oil production by about 5% sequentially and roughly 25% year-over-year. However, expected declines in natural gas production will limit our total second quarter production to a range of 685,000 to 695,000 BOE per day, so essentially flat with the first quarter. Third and fourth quarter oil production will be up in spite of the impact of a scheduled plant turnaround at the Jackfish 1 facility. We expect overall top line growth in the second half of the year as oil, NGL volume growth outpace any declines we may have in natural gas production. For the full year, we remain very comfortable with our previous guidance range. We are on track to produce in the range of 253 million to 257 million BOE in 2012. This will be driven by oil and NGL production growth of nearly 20%, shifting our overall production mix to 40% liquids by year-end. Looking at price realizations. As both Vince and John mentioned, unusually wide differentials had a significant impact on our first quarter results. In Canada, oil realizations came in at 61% of the WTI benchmark or a full 7 percentage points below the midpoint of our forecasted range. Weak refining margins as a result of mild winter weather and high refined product inventories led several refiners to simultaneously perform plant turnarounds. Concurrently, one of the major heavy oil refineries had an unscheduled outage. Finally, the first quarter start-up of a 130,000-barrel a day refinery that was converted to heavy oil ramped up much slower than we anticipated. As a result, Access Western Blend differentials widened from about $24 a barrel in January to more than $42 a barrel in March. Unfortunately, the wide March differentials persisted into April with Access Western Blend trading at roughly $42 a barrel under WTI. However, with many of the turnarounds complete and the converted refinery now running at capacity, that differential has come down to $26 in May. Also based on the first 2 trading days establishing June realizations, differentials to WTI are less than $20 now. Looking ahead, we expect our Canadian oil price realizations to average 60% to 66% of WTI for the second quarter, and 62% to 68% for the second half of the year. Price differentials for natural gas liquids were also much wider than expected. In the first quarter, our NGL realizations came in at 34% of WTI benchmark prices, also about 7 percentage points below the midpoint of our guidance range. Several petrochemical plant turnarounds in the Gulf Coast region reduced first quarter ethane and propane demand in excess of 120,000 barrels per day. This represents roughly 10% of U.S. petrochemical demand for NGLs. Additionally, very low natural gas prices and high inventories of propane, as a result of the unusually warm winter, also put downward pressure on NGL prices. This weakness has extended into the second quarter, and we now expect our second quarter realizations to range between 32% to 38% of WTI. Late in the second quarter of this year, many of the petrochemical plants will complete their turnarounds and the conversion of an existing plant to ethane and propane feedstock will add up to 60,000 barrels per day of incremental demand. As a result, NGL realization should recover to the point where our second half 2012 NGL prices should average between 34% and 40% of WTI. Looking briefly at our hedges. In the first quarter, our hedge position delivered cash settlements of $158 million. In total, these cash settlements enhanced Devon's average realized price by $2.50 per barrel, an uplift of 8% to company-wide realizations. Since our update at year-end, we have continued to bolster our hedge position for both oil and natural gas. On the gas side of the business, we increased our 2012 hedge position to approximately 1 Bcf per day. This represents about 40% of our expected production for the remainder of the year with a weighted average protected price of $4.42 per Mcf. The strong oil markets have also provided a good opportunity to add attractive hedges. For 2012, we have 109,000 barrels per day hedged, or about 70% of forecasted production with a weighted average floor price of $95 per barrel. For 2013, we have 72,000 barrels per day hedged with various swaps and costless collars. Of this amount, 31,000 barrels were swapped at a weighted average price of $104, with the balance collared at a weighted average ceiling of $117 and a floor of $91. If you would like more details on our hedging position, please visit the guidance section of our website that Vince referenced earlier. Turning now to our marketing and midstream operations. Our first quarter operating profit totaled $112 million, enhancing our company-wide margin by $1.78 per BOE. Looking ahead, downtime related to an expansion of our Gulf Coast fractionators facility in Mont Belvieu will limit our midstream operating profit to a range of $70 million to $90 million in the second quarter. Once this expansion is complete, we expect our midstream operating profit will rebound to a range of $110 million to $140 million per quarter in the second half of the year. However, based on the weakness we are seeing in the first half of the year, we now expect our marketing and midstream profit to be about $50 million below our previous guidance. Moving to expenses. As John said, we continue to do a good job of controlling cost. Cash expenses were generally in line with our guidance. However, noncash DD&A came in at $680 million or $10.78 per barrel, about $0.13 above the high end of our guidance range. Over time, our DD&A rate continued to gravitate toward our average mining and development costs. With our current focus on higher returning, but higher cost oil projects, we expect our DD&A rate to migrate higher in upcoming quarters. In the second quarter, we expect our DD&A rate to range between $10.80 and $11 per barrel. Looking specifically at cash costs. Pretax cash costs in the first quarter totaled $13.80 per BOE, a 1% increase compared to last quarter. By achieving significant scale in core operating areas, coupled with our consistent focus on cost management, we are positioned with one of the better cost structures in the industry. This is especially impressive given our shift to more oil projects, which are generally more expensive to produce. The final expense I will touch on is income taxes. After backing out the items that are typically excluded from analyst estimates, our adjusted first quarter 2012 income tax rate was 32% of pretax earnings. The adjusted rate is comprised of a 3% current rate and a 29% deferred rate, right in line with our guidance. In today's earnings release, we have provided a table that reconciles the effects of items that are typically excluded from analyst estimates. I'll conclude with a quick review of our financial position. In the first quarter, our operating cash flow before balance sheet changes totaled $1.4 billion. On a per share basis, cash flow increased 3% compared to the first quarter of 2011. Early in the second quarter, with the closing of the Sinopec transaction, we received roughly $900 million in cash. As we stand today, our cash and short-term investments totaled $7.7 billion and our net debt is just $2.5 billion. Pro forma for the close of this transaction, our net debt to cap at the end of the first quarter was less than 12%. Clearly, from a balance sheet and liquidity perspective, we remain exceptionally strong. At this point, I'll turn the call back to John. John?

Thanks, Jeff. Well, in summary folks, while the first quarter earnings were negatively impacted by unusually low price realizations, our positive operating results reflect the continued execution of our business plan. We delivered year-over-year oil production growth of 26%. We were very successful in bolstering our drilling activity with significant oil-focused leasehold capture. We comfortably funded our robust capital program while maintaining a strong financial position. We did a very good job of controlling costs in a rising industry cost environment, and as we've said many times in the past, we remain fully committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength and optimizing our cash flow growth on a per debt adjusted share basis. So with that, I'll turn the call back over to Vince for our Q&A.

Operator, we are ready to take the first question.

[Operator Instructions] Your first question comes from Jessica Chipman with Tudor, Pickering, Holt. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Thank you for all the color on NGL pricing. I have one question related to that. At the Analyst Day, you showed Barnett returns at about 17%, assuming $250 gas, $100 oil and NGL realizations at 47% of WTI, can you talk about how your returns are impacted by lower NGL realizations that we're seeing today? And is there any chance you would rethink your Barnett plans until NGL realizations improve?

Jessica, we have taken a look at it. And then I guess, the quick answer is, we won't change our view as long as the economics remain positive. We did just stress test. That was actually subsequent to our Analyst Day, we stress tested both the Barnett and Cana, because they're both liquids-rich gas projects, for our ongoing capital allocations. And of course, when we're doing that, probably goes without saying, what we're really looking at is a program moving forward and a drilling program moving forward, and that's more dependent on 2013 prices than it is where we are today. But just to run some sensitivities, I'll give you a few numbers here. At a $2 realized price, so let's get back to what we're actually getting, rather than these benchmark prices. The $2 realized price and about a $33 realized natural gas liquids price, and if you factor in the midstream uplift that we get, which of course is integral to those operations, so we have to consider both of them, we see a high-teens rate of return in the Barnett Shale and somewhere around the mid-20s rate of return in Cana, which in either case, is way above our cost of capital, obviously. If you look at next year and think about what the -- and by the way, we don't think that the $2 realized price was what we're going to see in 2013 and beyond, but we did that to get a sensitivity. If you look at 2013 and prices that are probably more realistic, and take for example, a $3 realized price, now that would be just about where the strip is today. I think the strip's about $3.50 or something, so a $3 realized price is probably pretty close. And again, a $33 NGL price, with the midstream uplift, that gets you to about a 20% rate of return in the Barnett, and close to 30% rate of return in Cana. So we're still pretty comfortable with those kinds of rates of return, particularly with the scale that we have in those plays. But we're constantly looking at that because with our deep portfolio, we can move our funds around to where we can make the most money for our shareholders, and so we're always watching that. Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, that's very helpful. Just a second question to you on capital spend. It looks like the run rate based on Q1 spend is actually lower than your total 2012 capital budget. Is there any chance you think you might be able to keep CapEx below budgeted levels?

Well as John says, we're constantly looking at the results of our budget, and it's certainly possible. But I'd point out that we've been assembling some large acreage positions that will hit principally in the second quarter. So we think, right now, we're still running about true to our forecast for capital.

Your next question comes from Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Following up real quickly on that acreage comment and tying into your Analyst Day where you indicated you'd like to increase your position into this line. Is it safe for us to assume that, that's where that capital is being deployed that Vince just mentioned? And any indications you could give us around price per acre in that play would be very helpful.

Yes, first, it's not safe to assume, while we would like to increase our position in the midst, we have not disclosed where those incremental acreage acquisitions are. And any place that we want to increase our acreage position, we aren't really willing to talk about specific transactions and the cost trends in that acreage. David W. Kistler - Simmons & Company International, Research Division: Okay, sorry. I had to give it a try. And then just looking at the Wolfcamp results on the Avid [ph] 17H well, can you talk a little bit about cost and design and where that's targeted over time?

Yes, hi Dave, this is Dave Hager. This is a -- to give you an idea on cost, and again, this is the first well that we've drilled over in our Wolfberry area. This is actually, in the what we call our Odessa South area of the Midland Basin. It's really, geographically, if you want to know where that's located, it's in the far southeast corner of Ector County, and that well looks like it's going to cost somewhere around $5 million or so. It looks like we're going to have probably on the order -- it's very early, so it's really, we only have about 20 days or so. But we're estimating somewhere around 300,000 barrels net EUR on that. And we have, in that particular well, completed it in the Wolfcamp B interval. That's really where much of the activity has taken place with the industry. We have in back in our main core Wolfcamp shale, we have completed some in the Wolfcamp A, as well as some in the, we think the C and D zones also in our perspective. But we played it conservative with this first well. It's 80 miles away from our production state in the Wolfcamp B. David W. Kistler - Simmons & Company International, Research Division: Okay. And any just color on lateral length frac stages, and then where that cost could trend?

I don't have, I don't think, the number of frac stages sitting in front of me right now. But we've completed, I believe very similarly to how we did our other Wolfcamp Shale wells. So I think, again, that we're still on, very much on the learning curve on our Wolfcamp Shale wells. It was a 3,800-foot horizontal on that particular well. But we're still -- I would have to lump that in with the rest of the Wolfcamp Shale. But we're still on the learning curve, and we showed at the Resource Update how we're continuing to improve on the cost side of it. And we stated there, we think the key is to get out as far laterally as we can, 7,000-foot plus on the lateral length. And so this is really encouraging results, I think, given that this is only 3,800-foot lateral, and future wells with experience in this area maybe even to be able to take out significantly further and get even better EURs.

Your next question comes from Brian Singer with Goldman Sachs.

Just following up on that question on the Wolfcamp well in Ector County, when you got into the interval itself, into the Wolfcamp B, how did geologic characteristics there compare with what you have seen in the wells you've drilled 80 miles away to the Southeast?

Well, we think it drilled and completed very similarly to what we saw to the Southeast.

Okay. So is it your view then that the bulk of kind of what you have in between, which I know is a bit more focused on the Southeast, it is going to be perspective, and or do you see any differences based on what you've seen so far?

Well, it's a 6-inch hole 80 miles away, so there's a lot of ground in between. So there's -- we're certainly encouraged, I think, as I said in my comments, we need to do more study. And we need to drill some more wells, but we're certainly very encouraged by our initial well. And that it could add a significant new Wolfcamp resource on our Wolfberry acreage. But again, this is the first well. So I don't want over-characterize this, but it's certainly encouraging, what we've seen so far.

That's fair. Is that well on pump at this time?

No.

Okay, and then separately on the CapEx trajectory, how should we expect the next couple of quarters here relative to the, I guess, $2.1 billion or so that showed up in the cash flow statement for CapEx. You highlighted I think earlier that you should see acreage acquisitions pick up here in the second quarter. But when we think about the next few quarters, should we see similar trends or higher trends overall relative to Q1?

Brian, it's Jeff. We would expect to see a little bit more lumpiness in the second quarter, but more of a, more normalized in the third and fourth quarter, consistent with what we saw in the first.

Great. And then lastly, on the Tuscaloosa, I think you mentioned you moved the rigs north here, testing a couple, 2 to 3 wells. Do you see any differences so far or even in your base case on the geological characteristics there versus the wells that you've drilled already in the South?

Well, it's a little bit early, I think, to draw any conclusions to that. We do think that we're seeing some of that evidenced at the acreage to the North is, looks like it may be more -- a little bit more frac-able. But again, this is very early, and we're talking about just a very few number of wells across a multicounty area. So I would be hesitant, geologically, to draw too many conclusions till we get more data. But that's, if you want a very early indication, I can say that. But again, I don't consider that real definitive at this point.

Your next question comes from David Tameron with Wells Fargo.

A couple of questions. Granite Wash, can you talk about what you're chasing there, and what zones do you hit for those, like you gave some numbers of 650 BOE, or 1,650 BOE?

Well, we're chasing, primarily, the Cherokee and Granite Wash A with those completions. We do have additional potential in the deeper Granite Wash zones. We have quite a bit of a potential associated with those. The wells we're drilling right now are chasing primarily the Cherokee and the Granite Wash A.

Okay. And then on NGL pricing, and I don't know if it's Jeff, whoever answered the question about NGL, is there anything you can do on the hedge front? I mean, do you try to put on dirty hedges to protect that, or how do you go about doing that? If you choose to?

Yes, this is Darryl Smette. We really have not been very active on financially hedging our NGL position. And that typically has been what we perceive to be lack of liquidity in the NGL market. Now that might change as we go forward, as more NGLs come on the market. But right now, we think there's been lack of liquidity, so we think there's going to be a lot of variation. And we also look at the back end of, whether it's 1-year, 2-year or 3-year, we see a tremendous decrease in price in those outer years. So we have not been very active. Although we do have a few hedges in place on natural gas lean, but it's minor. So until we become comfortable, quite frankly, with the liquidity, and until we see what we believe are reasonable market prices in the outer years, we probably won't be very active in the financial hedges on NGL.

Your next question comes from Doug Leggate with Bank of America.

I've got a couple also. One on financials and I guess, the other operational. Just on the hedging, it looks like you guys have been really very successful in being able to lure in additional gas hedges at pretty attractive prices, considering where the strip is. I was just wondering if you could give a little bit of a color as to what was going on there in terms of, are you doing something different? Or is it still a fairly liquid market? What is the mechanism whereby you've been able to continue to lock in those prices, and I have an operational follow-up, please.

This is Darryl again. I'd like to say, we're just great, but I think, no probably, we're probably just a little bit lucky. What we try to do is anticipate where the markets are going to go, and recognize there's going to be a lot of volatility and that volatility may allow for some prices to be there for a short period of time so that people that are looking at it all the time. But we typically would do will become comfortable with the prices that we're willing to accept, and we give approval to our people who are watching this 24/7. And so when the prices for whatever period of time, they're on the screen and we can commence transactions, they're prepared with approval to do that. So we try to plan ahead. We give our people authorizations. We have people manning the screens 24/7, so we feel pretty good that when they're only there for a period of time, we're able to do something, because there's nothing magic in it other than that, Doug.

So these are pretty clean swaps and callers. There's no call sales or any front-line going on?

We have a few calls for 2013, 2014 on oil that I think are $120 for about, I don't know, 10,000 barrels a day. And I think $5 on the gas side, which allowed us to lock in a $450 price for 2013 on gas. But that's all the calls that we have going forward.

So a very minor amount.

Yes, very minor amount. We tend to-- we tend to play pretty straight with simple type of transactions you can do and try not to complicate it too much. Our experience has been when you try to complicate it too much, that it tends to confuse a lot of people, including us, sometimes. But it seems every time we get into some confusing types of transactions, we're always a little leery whether we really understand what we're doing, so we try to keep it pretty simple.

Got it, thanks for the clarity. My operational follow-up is, I think David, you touched on a little bit of the exploration phase, but I wonder if I could just dig a little bit more into the Utica. Obviously, we're watching this very closely to see how your acreage play turns out. I'm just wondering if you could give us a kind of line of sight of what we can expect out of the Utica in terms of activity levels, well results and maybe clarify if you are still adding to your acreage position out there now.

Yes, right now, we've drilled our -- as I said, our first well, and we're completing our first well started to flow back on the Eichelberger well. This is really on the Western side of Ashland County, which we believe is kind of right in the peak of the oil, the heart of the oil play, I would say. So -- and it is a significant test. And obviously, we recognize the oil part has some risk associated with it, but I went through on the Resource Update why we think we have good permeability and it has a good chance to work. The second well that we've drilled out there, the Richman Farms is a little bit to the Northeast, it's in Southwest Medina County. It's probably, from an oil standpoint, is probably not -- we don't anticipate it being in a lot different position than where the first well is. And then we're going to be -- the third well we're drilling is called the Sinsabaugh [ph] Well, and it's located significantly to the South there in far -- Southern Knox County or Northern Lincoln County in there. And it still, though, is going to be very much in the oil window. After we -- after those 3 wells, we're actually going to release that rig for some period of time. And then we're going to go back and pick up a higher horsepower rig that's required to drill our acreage a little bit further to the East, to which we think is closer to the liquids-rich window. And so we'll we picking up activity further to the East, more in Coshocton County, Guernsey County, it's in that area. And I might mention that we're also participating in the completion of a well where the intervest is operating the RHDK well that's in far Northwest Guernsey County and they're moving forward with the completion of that well. We are not, at this point, adding additional acreage. We want to see the results of what these wells are. We're happy with our position. Obviously, the further you move east then our acreage position becomes more liquid-rich, and probably a lower risk, but not necessarily the economics would work great if the oil window works well, and that's what we just need to find out for sure.

Your next question comes from Joe Magner with Macquarie.

Can you give us a breakdown of the NGL mix and how much of that's been sold at Conway versus Mont Belvieu?

Yes, this is Darryl again. Just to give you an overall mix for Devon, we have about 8% to 10% of our NGLs in Canada. Have about 10% of our NGLs that are primarily in the Rocky Mountains that are marketed at Conway or sold at Conway. The rest, the other 80%, 82% whether that's Mid-Continent from Cana, Bridgeport, Northridge and most of our Permian Basin find a home in -- at Mont Belvieu. In terms of mix, we have about 57% to 58% of our product is ethane. About 23% or thereabouts is propane. The remainder is ISO normal and natural gasoline. We tend to be a little bit more ethane than a lot, or some of the other plays. A couple of reasons for that. One is that most of our facilities are rather new-facility cryogenic plants and they're very efficient, and therefore, we get a deeper cut on the ethane than a lot of the older plants that are either refrigeration or some of the cryo plants were put in place 10, 12 years ago. The second part of that is that, in some of our plays God just put more propane in our mix. So those are kind of the 2 drivers.

And I guess, given some of those details, can you just give us, I guess, some outlook for what you all are seeing in terms of near-term prices and how market fundamentals between those 2 pricing points might change or evolve or improve in Mount Belvieu?

Yes, sure will. We really have not seen much change in the prices for the products through April and May. As we see a lot of the petrochemical plants come back online, and we do have the one conversion that's being put in place that Jeff talked about, the scale had about, I don't know 50,000, 60,000 barrels of demand. We expect we're going to start seeing the product prices increase both for propane and ethane. Probably not to the extent that we saw last year. Because of the very, very mild winter we have a tremendous buildup in propane supply. And probably 14 million, 15 million barrels more than we historically have. So we're probably going to see propane not rebound as fast as we're going to see some of the other products. We get to the end of the third quarter into the fourth quarter, we should see those product prices go up. As we look for the rest of the year, we're probably going to be somewhere in the 34% to 40% on a cumulative basis when you put all the products together. As we look into 2013, we have a number of fractionators that are coming on. And so we see product prices that are -- probably stay strong into the first half of 2013 as we get through the second have of 2013 into 2014 with all the additional frac coming on, with not a corresponding increase in petrochemical plant yet, we could be some -- under some pressure there, and we tried to model all of our projects with the -- a discount to NGL products as we get to the second half of 2013 and into '14.

Joe, this is Vince. I just might add that in line with what Darryl said, Jeff in the call modified our guidance for NGLs realizations for the second quarter to between 32% and 38% of WTI. And for the second half of 2012, 34% to 40% of WTI.

Yes, I picked up on those. I was just curious about some of the underlying changes there. In terms of new ventures, can you just, I guess, remind us how the Cline Shale differs or I guess is being categorized more of a development play versus exploration against some of the other, the 5 other new ventures programs?

Well, I don't know if I'd classify it as a pure development play, because there is obviously some risk associated with it. But some comments, there have been some other industry wells that have been drilled, primarily in Glasscock County just immediately to the West of a lot of our acreage position. And remind what I said at the Resource Update that a lot of those wells were drilled with 4,000-foot laterals where our models are built off of longer laterals on the order of 7,000, 7,500 feet. So we're anticipating higher EURs, higher IPs and higher EURs than what have been seen by the wells that have been drilled to date. But there are probably about 25 wells out there. So that gives you some confidence. And then if you look at it, there's probably been over 10,000 wells have been drilled through the Cline Shale for other intervals historically. And so that's given us a great deal of well control. But again, I don't want to mislead and say there's not risk. I think every time you enter one of these new plays, you have some risk associated with it, and that's another reason why we would consider also bringing in a partner on this play, but we really like the position, and we also see some prospectivity in other intervals. I won't go into a lot of detail on that, but we see prospects in other intervals, so it's more than just a pure Cline play.

Your next question comes from Harry Mateer with the Barclays.

Jeff, couple of questions for you on the balance sheet. I guess, first, if you can just remind us how much of that cash balance is offshore? And then second, on the debt side, your short-term debts continue to go up, as you guys have been spending cash flow, I know you still have a lot of cash, but what's the -- what's sort of the plan for the rest of the year with that short-term debt balance? Do you anticipate coming to the bond market? And I guess, related to that, can you just talk about your $750 million revolver drawer during the quarter?

Sure. I'll start with the last one first. As we were issuing commercial papers, we were approaching the $4 billion mark on commercial paper. We were finding that the incremental demand was harder and harder to find, so we elected to draw down a little bit on the revolver just to alleviate the pressure on our commercial paper program. This -- the other question about our cash balances, and I'm sorry, I'm jumping around here. I'm just doing by recall here, but the cash balance is -- the $7.7 billion that I mentioned in the call that we have now, most of that, about $6.8 billion is outside of the United States with the remainder a result of our closing of the Sinopec transaction in late April. We will be leaving that in a tax partnership account. I hate to get into all these details, but it's sitting in a tax partnership account that we'll leave there. And then later in the early third quarter, we will be pulling that, a large portion of that out and paying down short-term borrowing balances. And the extent of that will be close to $600 million, which is basically our basis in the assets that we contributed to the tax partnership with Sinopec. And then as far as our overall liquidity goes, I mean, we're continuously monitoring that, and it will depend upon -- any access to the bond market would depend upon spending levels and short-term funding needs. But we've got a tremendous amount of liquidity and an ability to fund our U.S. business without any problems at all.

At that -- this point, the question queue is empty, so we'll terminate the call. Thank you for participating.

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