德文能源 (DVN) 2012 Q1 法說會逐字稿

Welcome to Devon Energy's first-quarter 2012 earnings conference call. At this time all participants are in a listen-only mode. After the prepared remarks we will conduct a question-and-answer session. This call is being recorded. At this time, I would like to turn the conference over to Mr. Vince White, Senior Vice President of Communications and Investor Relations.

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 will 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 will conclude with a Q&A period and as usual we will ask you to keep your questions limited to one and one follow up and we will 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. We will be refining some of those on 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 US 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 on today's call, we will 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 have 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 almost entirely due to unusually wide differentials on Canadian oil and US 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 will 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 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 continued 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. Pre-tax cash costs per unit of production increased only 1% from the last quarter of 2011. 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 $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 in 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. 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 risk 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 costs. Our biggest addition is our recently unveiled Cline Shale oil play. This is a 500,000 net acre position that we've assembled in the Permian Basin, and that was assembled at very reasonable costs.

We're also building a large, concentrated position in another oil prospect that is 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 is 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 are 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 new 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. 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.

With that, I will turn the call over to Dave Hager for a more detailed review of our operating highlights.

Thanks, John. Good morning, everyone.

Given the in-depth update we provided just a month ago at our analyst day, I will 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 are off to an outstanding start this year with record production from each of our four cornerstone development project areas; Jackfish, the Permian Basin, the Barnett, and Cana. We also continue to move forward with evaluating and de-risking 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 two 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 of this total, and continued its trend of excellent plant reliability and efficiency. At Jackfish 2, production continues to ramp up and we are 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 3-D seismic. Although we are 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 the 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 plays currently represent some of the highest return opportunities in our portfolio. Since year end, we have continued to ramp up activity with the addition of five 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 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 are continuing to fine tune our drilling and completion techniques. We brought two 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 Averitt 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 a 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 drawing 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 continued 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 and the Granite Wash play, we continue to see solid results from our Cherokee and Granite Wash wells. We brought six 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 the Sinopec JV and continue to move forward with the de-risking of the five 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 two rigs running and two wells completing. We expect to drill or participate in roughly 50 wells on this acreage by year-end, including tests of additional formations.

In our Rockies oil exploration, as we previously indicated, we are 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 are currently drilling wells testing two additional formations, the Mowry in the Powder River basin and the Cordell in the DJ Basin.

In the Tuscaloosa Marine Shale, we drilled our first two wells in the southern portion of our acreage position. As discussed during our recent update, results of the first two wells were somewhat disappointing. We have since moved our two operated rigs north and have two wells currently drilling and a third well that is roughly halfway through completion operations. These three 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 Wily 1H, and we should begin completing that well in a couple 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 a key going forward.

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 is awaiting completion and are currently drilling our third well in the play. We should have all three wells online by the end of the second quarter.

In summary, our 2012 capital program is off to a great start. With record production in each of our four cornerstone development areas, we are poised to deliver outstanding liquids growth. We have (inaudible) by 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 will turn the call over to Jeff Agosta for the financial review and outlook.

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 or were 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 and 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, accessed 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 accessed 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 two 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, or 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 US 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 updated year-end, we had 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 a $1.78 per BOE. Looking ahead, downtime related to an expansion of our Gulf Coast fractionator's 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 costs. Cash expenses were generally in line with our guidance. However, non-cash 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 will continue to gravitate toward our average finding 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, pre-tax 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 pre-tax 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 will turn the call back to John.

Thanks, Jeff.

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 have said many times in the past, we remain fully committed to exercising capital discipline, maximizing margins, maintaining our balance sheet strength and optimizing our cash flow growth on a per debt adjusted share basis.

With that, I will turn the call back over to Vince for Q&A.

Operator, we are ready to take the first question.

(Operator Instructions). Jessica Chipman, Tudor, Pickering, Holt.

Thank you for all the color on NGL pricing. I had one question related to that. At the analyst day you showed Barnett returns at about 17% assuming $2.50 gas, $100 oil and NGL realizations of 47% of WTI. Can you talk about how your returns are impacted by lower NGL realizations that we are seeing today? Is there any chance you would rethink your Barnett plans until NGL realizations improve?

Jessica, we have taken a look at it and I guess the quick answer is we won't change our view as long as the economics remain positive. We did just stress test, it was actually subsequent to our analyst day, we stress tested both the Barnett and Cana because they are both liquids rich gas projects, for our ongoing capital allocations. Of course, when we are doing that, it probably goes without saying what we are really looking at is a program moving forward and a drilling program moving forward and that's where 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 -- at a $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-20%s 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 -- by the way, we don't think that a $2 realized price is what we are 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 is about $3.50 or something, so a $3 realized price is probably pretty close. 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. We're still pretty comfortable with those kinds of rates of return, particularly with the scale that we have in those plays, but we are 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.

A second question too 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 that you may be able to keep CapEx below budgeted levels?

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

Dave Kistler, Simmons & Company.

Following up real quickly on that acreage comment and tying it to your analyst day where you indicated you would like to increase your position in the Miss Lime, is it safe for us to assume that, that's where that capital is being deployed, that Vince just mentioned? Any indications you can 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 Miss, we have not disclosed where those incremental acreage acquisitions are. 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.

Then just looking at the Wolfcamp results on the Avit 17H well, can you talk a little bit about cost and design and where that's targeted over time?

This is to give you an idea on costs, and again this is the first well that we have drilled over in our Wolfberry area, this is actually 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 are going to have probably on the order of -- and it's very early, so it's really -- we only have about 20 days or so, but we are estimating somewhere around 300,000 barrels net EUR on that.

We have, in that particular well, completed it in the Wolfcamp B interval. That's really where much of the activity is taking place with the industry. We have -- and 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 are prospective, but we played it conservative with this first well. It is 80 miles away from our production and stayed in the Wolfcamp B.

Any just color on lateral length, frac stages, and 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 completed that I believe very similarly to how we did our other Wolfcamp Shale wells, and I think again, 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 are still -- I would have to lump that in with the rest of the Wolfcamp Shale where we're still on the learning curve and we showed at the resource update how we are continuing to improve on the cost side of it.

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. This is really encouraging results I think given that this is only 3,800 foot lateral and future wells with experience in this area may be able to take out significantly further and get even better EURs.

Brian Singer, Goldman Sachs.

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 the geologic characteristics there compare with what you have seen in the wells that you have drilled 80 miles away to the Southeast?

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

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

It's a six inch hole 80 miles away. There is a lot of ground in between. We are certainly encouraged. I think as I said in my comments that we need to do more study and we need to drill some more wells, but we are 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 to overcharacterize this, but it's certainly encouraging what we've seen so far.

Is that well on pump at this time?

No.

Then separately, on CapEx trajectory, how should we expect the next couple of quarters here relative to the $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?

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

Lastly on the Tuscaloosa, I think you mentioned you'd moved the rigs North here, testing a couple, two to three wells. Do you see any differences so far or even in your base case on the geological characteristics there versus the wells that you have drilled already in the South?

It's a little bit early, I think, to draw any conclusions to that. We do think we are seeing some evidence that the acreage to the North looks like it may be a little bit more frackable, but again this is very early and we're talking about just a very few number of wells across a multi-county area. So I would be hesitant geologically to draw too many conclusions until we get more data. If you want a very early indication, I can say that, but again I don't consider that real definitive at this point.

David Tameron, Wells Fargo.

Granite Wash, can you talk about what you are chasing there and what zones you hit for those? I think you gave some numbers of 650 BOE, or 1,650 BOE?

We are 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 potential associated with those. The wells we are drilling right now are chasing primarily the Cherokee and the Granite Wash A.

On NGL pricing, I don't know if it was Jeff or whoever answered the last question about NGLs, is there anything you can do on the hedge front? Do you try to put on dirty hedges to protect that? How do you go about doing that? If you choose to?

We really have not been very active on financially hedging our NGL position. 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 is going to be a lot of variation. We also look at the back end of whether it is one year, two year, or three 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. 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.

Doug Leggate, Bank of America.

I have got a couple also, one on financials and I guess the other operational. Just on the hedging, it looks you guys are being really, very successful in being able to layer 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 color as to what's 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 have been able to continue to lock in those prices? And I have an operational follow-up, please.

I would like to say we're just great, but I think 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 is 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 we have people that are looking at it all the time. What we typically will do is become comfortable with prices that we are willing to accept and we give approval to our people who are watching this 24/7, so when the prices for whatever period of time they are on the screen and we can commence the transactions, they are prepared with approval to do that. 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 are only there for a short period of time, we are able to do something. There's nothing magic in it other than that, Doug.

These are pretty clean swaps and collars, there's no call sales or anything like that going on?

We have a few calls, for 2013 and 2014 on oil that I think are $120 for about 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 is all the calls that we have going forward. Very minor amount. 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, it tends to confuse a lot of people including us sometimes. It seems every time we get in some confusing types of transactions, we're always a little leery whether we really understand what we are doing so we try to keep it pretty simple.

My operational follow-up is I think, David touched on a little bit of the exploration plays, but I wonder if I could just dig a little bit more into the Utica. Obviously we are watching this very closely to see how your acreage play turns out. I just wonder if you give us a 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 a few acreage positions out there. And I'll leave it there. Thanks.

Right now, we have drilled, as I said, our first well and we are completing our first well, started the flow back on the Eichelberger well. This is really on the Western side of Ashland County which, we believe, is right in the peak of the oil, the heart of the oil play I would say. 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 Richmond Farms, is a little bit to the Northeast. It is in Southwest Medina County, and it's probably, from an oil standpoint, it's probably -- we don't anticipate it being a lot different position than where the first well is. The third well that we are drilling is called the [Sinsobal] well, it's located significantly to the South there in far Southern Knox County or Northern Looking County in there. It still though is going to be very much in the oil window. After those three wells, we're actually going to release that rig for some period of time and then we are going to go back and pick up a higher horsepower rig that is required to drill our acreage a little bit further to the east, which we think is closer to the liquids-rich window. We will be picking up activity further to the east, more in Coshocton County, Guernsey County in that area.

I might mention, we are also participating in the completion of a well, where Intervest is operating the RHDK well that is 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 in our acreage position, becomes more liquids rich and probably a lower risk, but not necessarily the economics were great if the oil window works well and that's what we just need to find out for sure.

Joe Magner, Macquarie.

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

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 is Mid-Continent from Cana, Bridgeport, Northridge, and most of our Permian Basin, find a home 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 are very efficient. 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 that 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. Those are the two drivers.

Given some of those details, can you just give us some outlook for what you all are seeing in terms of near-term prices? And how market fundamentals between those two pricing points might change or evolve or improve through the balance of this year?

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 is being put in place that Jeff talked about, that's getting about 50,000, 60,000 barrels of demand, we expect we are 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 build-up in propane supply and probably 14 million, 15 million barrels more than we'd historically have. We are probably going to see propane not rebound as fast as we are going to see some of the other products, but 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 are 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 probably stay strong into the first half of 2013. As we get through the second half of 2013 into 2014, with all the additional frac coming on with not a corresponding increase in petrochemical plant yet, we could be under some pressure there and we've tried to model all of our projects with a discount to NGL products as we get to the second half of 2013 and into '14.

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 remind us how the Cline Shale differs or is being categorized more as a development play versus exploration compared to some of the other -- the five other new ventures programs?

I don't know if I can classify it as a pure development play, because there is obviously some risk associated with that, 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, 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 to 7,500 feet. We are anticipating higher EURs, higher IPs and higher EURs than 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.

If you look at it, there has probably been over 10,000 wells have been drilled through the Cline Shale for other intervals historically. 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. 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 and I won't go into a lot of detail on that, but, we see prospectivity in other intervals. So it's more than just a pure Cline play.

Harry Mateer, Barclays.

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

I will 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 our revolver just to alleviate the pressure on our commercial paper program.

The other question about our cash balances, I'm sorry I'm jumping around here, I'm just doing them by recall here. The cash balances, 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. 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. 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. As far as our overall liquidity goes, we are 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 US business without any problems at all.

(Operator Instructions). Barbara Chapman, BNP Paribas.

Hi, I think Harry got most of my questions. Thank you.

At this point, the question queue is empty, so we will terminate the call. Thank you for participating.

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