德文能源 (DVN) 2005 Q1 法說會逐字稿

Hello and welcome to the Devon Energy Corporation's first quarter earnings conference call. At this time, all participants are in the listen-only mode. After the presentation, we will conduct a question and answer session.

[Operator Instructions]

At the request of Devon Energy, this conference is being recorded for instant replay purposes. If you have any objections, you may disconnect at this time.

I would like to turn the conference over to Mr. Vince White, Vice President of Communication and Investor Relations. Sir, you may begin.

Thank you. Welcome to everybody to Devon's first quarter 2004 conference call and web cast. As usual, I have a few opening remarks, and then our Chairman and CEO, Larry Nichols, will give us an overview of the quarter and update you on the status of our share repurchase program and of our North American property divestitures. Following Larry's remarks, John Richels, our President, who will review the operating highlights. Then CFO Brian Jennings will review the first quarter financial results, and the outlook for the future. Following Brian's comments, we will open the call out to Q&A, and we generally limit the calls to one hour, but the staff will be around today to answer any follow-up questions you may have.

Before we get to the business of the call, I have got a couple of reminders. First, during the call, we will refer to forecast estimates and expectations. These references are defined as forward-looking statements, and although we always strive to give you the very best information possible when we make an estimate, we run the risk that the actual results will differ. For discussion of the risk factors that could cause that to happen, I will refer you to our form8-K filed on February 2, 2005.

I will also remind you that our full-year forecast apply only to Devon's core oil and gas properties. That is they exclude the contribution of the non-core properties that we are in the process or actually just completed divesting. Our actual reported results include production from the divested properties through the closing dates of the sale.

So there is a difference in the full-year guidance and the reported results. We provided a separate first quarter forecast for the divestiture of properties. And since many of the divestitures will not actually close until the second quarter, later in the call Brian is going to give you some information on some guidance on the second quarter production from the divestiture assets. We will also provide a detailed estimate of the production and expenses associated with the divestiture properties in our form 10-Q for the first quarter, which we expect to file later this week.

One other item I need to cover is to point out that in today's call, we'll provide certain metrics that are defined as non-GAAP performance measures and under current US Securities Law, when you use non-GAAP measures, you are required to provide reconciliations to the closest GAAP performance measures, along with what we call a utilities statement, and explanation as to why the non-GAAP measures are useful.

And that information can be found on our web site. That address is www.devonenergy.com. One final item throughout the call, any references we make to dollars are referring to US dollars. That includes when we talk about our Canadian operations.

With the housekeeping items out of the way, I will turn the call over to our CEO, Larry Nichols.

Thanks, Vince. The first quarter of 2005 was really a very solid one for Devon, net earnings and earnings per share were both up from a year ago. On a reported basis, net earnings for the first quarter climbed 14% over the 2004 quarter, and that is coming up to $563 million.

Diluted earnings per share were $1.14 versus a $1.00 per share in 2004. Backing out the times that are typically excluded vinyl's models we earned a $1.12 per diluted share in the first quarter. This was $0.12 below the first call consensus. The biggest driver was oil price realizations that were lower. The results are from wider than expected quality differentials, especially in Canada. Brian will cover this in more detail.

During the first quarter, we continued to generate strong levels of cash flow, with cash flow before balance sheet changes topping a $ 1 billion for the 7th consecutive quarter. Also during the first quarter, we substantially completed our midstream divestiture program that's been under way since 2002. This is separate and apart from our oil and gas property divestitures that we announced last fall. It has always been our strategy to own midstream assets when they are needed to add value to our A and P business, with initial acquisition, we acquired some midstream assets that were valuable but not the strategy. This divestiture program eliminates those assets.

The proceeds from the midstream divestitures have totaled $330 million. Following these divestitures, we will retain ownership in 64 gas processing plants in the US and Canada with net processing capacity of over 2 billion cubic feet per day. It's worth noting that when we announced the Mitchell acquisition, we attributed initially $840 million in value to the midstream. When we closed to book on the deal that, value had risen to $1 billion, and now, after divesting $330 million of midstream assets, we're left with a business that is currently generating annualized EBITDA over $300 million, most of which occurs comes from our own Mitchell assets.

In addition to the cash we're generating from operations, and from the midstream divestitures, our oil and gas property divestitures promised to generate generous amounts of cash as well.

As we announced this morning, we have now finalized purchase and sale agreements for all the divestiture properties, and expect to have these transactions closed by the end of the second quarter.

The results exceeded our expectations by a very wide margin. We're divesting $166 million equivalent barrels of crude reserves about 8% of our total company wide reserves at year-end. With gross pre-tax proceeds exceeding $2.3 billion this works out to a little over $14 per barrel. The combined after-tax proceeds from the divestitures, that is all of the properties we have offered for sale both in the U.S. and in Canada exceed $2 billion. That's after tax. This is more than one half of a billion dollars over the top of our originally announced target range of 1 to $1.5 billion dollars. We are obviously very pleased with this result. The market for producing properties is very strong today and our results attest to the appetite of the market and to the quality of Devon's asset base.

Following our divestitures, Devon's property base will have more growth potential. We'll have more unit operating costs and will have a longer overall reserve life. We expect the combination of these divestitures and our 2005 capital program to lengthen our reserve life index by over a year.

With proceeds of the divestitures, and the ongoing free cash flow from operations, these are providing Devon with serious quantities of excess cash. We continue to strive to optimize the allocation of these funds among the various alternatives we have for building value. As we've said before, these alternatives include dividends, debt repayment, incremental capital investments and share repurchases. With regard to dividends in the first quarter, we again raised our cash dividend after doubling it in 2004. We increased it by another 50% in March. In addition, we're continuing to pay down our debt with most of the divestiture proceeds yet to come.

Our cash and short-term investments total over $2.4 billion today. $1.6billion of this is earmarked for retiring debt maturities that we have in '05and '06. Yesterday we announced our intent to redeem, next month all of our $427 million zero coupons senior convertible divestitures that are due in 2020. In addition to the cash redemption of these zeros, we expect to retire another $500 million in maturities later this year in July and in November. In addition, increase in our dividend and repaying debt, we also increased the momentum of our share repurchase program.

During the first quarter, we repurchased 12.7 million shares of common stock at a cost of $557 million. This brings our total repurchases through the end of the first quarter to 17.7 million shares for a total of $740 million. Through today, we have spent approximately $1 billion repurchasing 25 million shares. This puts us at the halfway point of our 50 million-share repurchase initiative. When we announced last September we intended to redeem 10% of our outstanding common shares, we had hoped to accomplish that by the end of the first quarter of 2006. We now expect the completion late this summer.

Following redemption of the zeros, and following completion of our share repurchase initiative, our diluted share count will decline to about $455 million, and 455 million shares in the fourth quarter.

When we have completed this initiative, we will evaluate the oil and gas price environment and the current relative attractiveness and the alternatives we have for excess cash. It is worth noting that based on yesterday's closing price for our stock, when we repurchase shares of debt; we are paying an enterprise value of about $13.25 per equivalent barrel of crude reserves in our post-divestiture high-graded property base. This is before attributing any value to our very significant midstream division. If you allocate $2 billion of value to the midstream, which is a pretty modest value for a business that is generating roughly $300 million a year of EBITDA, that reduces our enterprise barrel cost to $25.05.

In addition, we get a non-core Barnett, our deep-water gold exploration, high impact international exploration and all the other unproved properties that Devon has across North America as a bonus. Based on the recent transaction prices that the market is seeing in several of these areas, particularly the deep-water gulf and the Barnett Shale, these are obviously very valuable assets. Suffice it to say, we believe Devon's stock represents a very attractive alternative use for our surplus cash. This is especially evident when you compare to the $14 per barrel that our non-core properties are bringing.

I will now turn the call over to John Richels who will cover the first quarter of operations.

Thanks Larry. Operationally, we had a very busy first quarter. At the end of the March, with the Canadian winter drilling program winding down, we still had 125 rigs running company-wide, with about half of those drilling on Devon operated wells. Activity levels are even higher than that during the quarter while the winter drilling season was in full swing.

During the first quarter, we drilled a total of 685 gross wells, 129 of which were exploratory wells, and 556 of which were development wells. About 89% of the exploratory wells were successful, as were 99% of the development wells. Capital expenditures for exploration and development totaled $945 million in the first quarter, which represents about one-third of our full year E&P budget. Because of the concentrated level of activity in Canada during the first quarter, that's pretty typical for us.

Our Canadian staff had a busy winter drilling season, drilling a record 384 wells, which is roughly 20% above the first quarter 2004 drilling activity level. Of the 384 wells drilled during the quarter, Devon operated 285. Our overall success rate for the winter program in Canada was 97%, and at the peak in January, we had 64 operated rigs running in Canada. This level of activity was particularly notable given that early warm weather cut the winter drilling season short by 2 to 3 weeks.

Despite the unusually short winter, we got most of the wells tied in with only 67 successful wells not tied in when activity was suspended. 42 of those wells will be tied in to production in the second quarter, and the remaining 25 wells will be tied in after it freeze up in the 4th quarter. I will mentioned a few specific operating areas in Canada. The Deep basin continues to be a major focus for us in Canada and this winter we drilled 77 wells in the Deep Basin with very good results in the Wathedy (ph), Belleville and Pinto areas. One notable, 100% working interest well in BILBO came on stream at 33 million cubic feet of gas per day.

We also drilled 41 wells in the Peace River Arch, with a 95% success rate in our both program, and 100% success rate in Cecil area. In North Eastern British Columbia, we drilled 109 wells with a 98% success rate. We're also gearing up activity at Jackfish, which you will recall is our thermal heavy oil project in the Alberta oil sands. We have begun site preparation and facilities construction, and we expect to begin drilling wells there in June. We're also planning construction of two 200-mile pipelines in the same right away. One is a 16-inch line with an initial capacity of 80,000 barrels per day, that's designed to transport DELU into Jackfish.

The second is the 24-inch blended crude system with a capacity of 200,00 barrels per day, back to the Edmonton area where we can access pipelines to multiple markets. These lines will give us the flexibility to use a variety of blending stocks as diluents. During the first quarter we drilled 42 stratographic wells on our acreage positioned to west of Jackfish and based on our initial evaluation, it appears we may have the potential to expand the Jackfish project onto that acreage. If we do pursue the expansion of Jackfish, the capacity of the pipelines can easily be increased with additional pumping capacities.

Moving now to the US Onshore, let's start with the Barnett Shale field in north Texas. In the Barnett Shale, we were running 15 rigs at the end of March, all operated by Devon. Of the 15 rigs, 9 were drilling inside the core, and 6 were drilling outside the core. We completed a total of 47 wells in the first quarter, of which 29 were located in the core area, and 18 of which were located outside the core. Of the 29 wells in the core area, 11 were horizontal wells. Full year plans are to drill 70 vertical wells and 55 horizontal wells in the core area, and about 100 horizontal wells outside the core.

However, we're currently considering accelerating our 2005 Barnett Shale activity. In Johnson County, we currently have four horizontal rigs running, one additional rig has been secured, and we also plan to add a sixth rig later in the year. Initial production rates from the horizontal wells vary, but we continue to bring on new wells both inside the core, and outside the core at initial production rates that are typically in the 2 to 3 million cubic feet per day range.

Devon's net Barnett Shale production averaged 554 million cubic feet of gas equivalent per day in the first quarter, with about 44 million per day coming from outside the core. However, our Barnett Shale production has been climbing, and last week it exceeded 570 million cubic feet per day.

As of March 31st, Devon had interest in 1,943 producing Barnett Shale's wells. Of this total, 172 were horizontal. 99 of which are located inside the core, and 73 of which are outside the core. Just to put that into context, the 172 horizontal wells that we have an interest in are four times the number of any other Barnett operator.

With such a large producing base, even minor incremental improvements in field performance and recoveries can be very meaningful. With that in mind, we have several projects underway to improve the effectiveness of our gathering systems. In addition, we have identified four pilot areas in the core area where we plan to drill 20 acre instill wells this year. We will keep you posted on the results.

Moving to East Texas in the Carthage area, we added a fifth rig for the first quarter, and in March, drilled the 23rd well of the 83 operated wells that we have planned for the year. This level of activity compares to our 2004 program of 64 operated wells. Our net production at Carthage averaged just under 200 million cubic feet per day of gas equivalent in the fourth quarter, which represents a 22% increase over the first quarter of 2004, and 4% increase on a sequential quarterly basis.

In South Cartage, we drilled seven 100% working interest wells in March with average production rates of 2.2 million cubic feet per day and gathering system upgrade in the South Carthage that we completed in the first quarter added about 13 million cubic feet per day of capacity.

Also, in Carthage we have initiated a 20-acre infiltrate study that has the potential to add significantly to our current inventory of more than 248 locations. Not from Carthage in north Louisiana, Devon holds about 200,000 acres in the Bossier play. We built this acreage position both through the acquisition in Santa Fe, and through subsequent leasing activity the Bossier play have been moving from west to east, which is our acreage is concentrated. At the economics of play have continued to improve.

In the first quarter, we drilled a Bossier well that tested at 11 million cubic feet of gas per day. This is a Devon operated well in which we have an 87% working interest. We are also currently drilling an exploratory prospect in the area with a 300BCF target. This is one of many high potential Bossier prospects that we have identified on our acreage. In late 2004, we began a limited exploration program on our gulf coast acreage, and in the first quarter, we had a very nice exploratory discovery in South Louisiana in the Patterson field.

Our test of the prospect, which is called Berwick, resulted in a high rate oil and gas well. The 18,000 foot discovery well came on at about 3,800 barrels equivalent per day and most of that is in the form of oil. This looks like a large reservoir and we think we can increase the production to 5,000 equivalent barrels per day. A full simulation study is planned to determine the optimum development scheme, and Devon is the operator of this prospect. We have 50% working interest.

Moving west to the Rockies, we have been running six operated rigs in the Washakie area, through our program there, we initiated the drilling of 18 wells and tied 13 wells into production in the first quarter.

Our full-year plans are to drill 55 operated new wells in Washakie and re-complete another ten wells. Devon's current net production in Washakie is about 90 million cubic feet of gas equivalent per day. We're now entering the spring period when drilling is restricted. However, we plan to keep our rigs working in other rocky mountain areas so that we'll have them available when we can resume drilling in Washakie around July of this year.

Turning now to the offshore US I will begin with an update of our deep water development projects and then review our gulf exploration programs. Firstly, on our Magnolia deep-water project in garden banks 783, two Magnolia wells were on-line at the end of March producing about 7,000 equivalent barrels per day, net to Devon 25% interim. These results have exceeded our expectations and Magnolia is producing a proper budget. A third producer was completed at the end of April.

We expect to have a total of 8 wells on stream later this year. Magnolia is located in 4,700 feet of water, and as many of you know is operated by ConocoPhillips. At Nansen, which is located primarily on east rigs 646, we began a four well re-completion program in the first quarter with excellent results.

As a result of the re-completions, Devon's net production from Nansen increased by over 9,000equivalent barrels per day. Devon has a 50% interest in Nansen and our share production is currently about 28,000 Devon's per day. In the Eastern Gulf we are now fabrication facilities at Organza in the out water valley area, and have two wells planned for the second of half of 2005. Organza will produce the independence hub, which is moving towards the scheduled completion date in 2007. Devon has a 50% working interest in Organza.

Turning now to Devon's Gulf of Mexico exploration program, that program is focused on the 3 play types deep-water lower tertiary, the deep water Miocene and deep shelf. In the lower tertiary trend, much of our 2005 activity is focused on delineating our previous discoveries. In the first quarter, we began drilling the first placer well to our 2002 Cascade discovery on Walker Ridge 206.

The plan total depths that Brazil well is about 28,000 feet, and we're currently drilling below 26,000 feet. DHP operates Cascade, and Devon has a 25% interest. Also in the lower tertiary trend, we began drilling an appraisal well on the Jack prospect in late April. Jack 2, with a target depth of about 30,000 feet follows a 2004 discovery on walker ridge 759.

Chevron Texaco operates the Jack prospect, and Devon has a 25% working interest in that prospect as well. We also plan to begin a second appraisal well later this year to our 2003 lower tertiary discover at saint Mallow, located on walker ridge 678. We now believe that it will be the first half of 2006 before production tests will be conducted on one of our lower tertiary discoveries. As a result, it's unlikely that any of the three projects will be sanctioned for developments this year.

However, the results of the three appraisal wells will provide more of the data necessary for an eventual sanctioning decision. In the deep-water Miocene, the Macaloo (ph) discovery exploration well was unsuccessful. This was Miocene test on Mississippi Canyon block 937, and Devon had a 12.5% working interest in that exploratory well. We're currently drilling the Chillcoot well on Green Canyon block 320. Chillcoot is a 30,000, sub salt Miocene test, which is operated by Kerr McGee. The well is being drilled in above 2,700 feet of water and Devon has a 27% working interest in this prospect.

Turning to the deep shelf we have several wells drilling first of all we are nearing total depths on the Joseph well, which is located at high island block 1O Devon has a 20% interest in this gas prospect which is operated by Shell. Joseph is a high potential lower tertiary test, however, unlike our deep-water lower tertiary discoveries, Joseph is being drilled in just 30 feet of water. Because of the shallow water locations, Joseph could be brought on production within a year and a half if it is successful.

We're also nearing expected total depths on the Devon operated Big Bend deep shelf prospect. Big Bend is located on Mustang island A-110 in about 300 feet of water and as a middle Miocene target of about 19,600 ft.

We have a 50% interest in big bend and given its location, this well could also be brought on line in about 15-18 months should it be successful. Still on the deep shelf, Devon has a 10% interest in the Cadillac prospect on Vioasca (ph) Knoll 251 being drilled in about 110 feet of water. Cadillac, operated by Chevron Texaco, is targeting the platen valley formation with a proposed total debt of 25,000 ft. Its currently drilling at about 20,000 feet. I will mention two other shelf exploration levels. The first is called racer. This is a 100% Devon well on west Cameron 175. The well is just penetrated the objective in the sands and we have seen strong hydrocarbon shows and good reservoir sands.

Racer is being drilled to about 15,000 feet. We are excited by the results, and will have a further update for you during our second quarter conference call. Given its location, racer could be tied in to production almost immediately. Also on the shelf, the 13,900-foot west Cameron 165A7 well was completed and put on stream in March at about 6 million cubic feet of gas per day.

However, this well has significantly more production potential up hole. The offset well is making about 10 to 12 million cubic feet per day from this uphold zone, and Devon has a 100% working interest in these wells. I'll finish this operational review with our international projects starting in West Africa.

The first exploratory well on block 256 offshore Nigeria, you may recall this was called the TARI prospect, was a dry hole. Devon's share of the dry hole cost is about $10 million. However, block 256 is a very large block covering more than 630,000 acres. Just to put that into perspective, that's roughly 125 times the size of a typical gulf of Mexico lease block, and we have many additional high potential prospects on this block, another one of which we plan to test later this year.

Devon's share of production from the sphere of fields on block B in Equatorial Guinea averaged 40,000 barrels per day in the first quarter. Consistent with what we mentioned in our fourth quarter conference call, the zero production declined in the first quarter, down about 5,000 barrels per day from the fourth quarter. This decrease reflects normal declines in gross field production, and also planned maintenance shut downs. Elsewhere on block B we're firming up plans to drill an exploratory well on the Esmeralda prospect this summer. Esmeralda has a growth unrest potential of more than 500 million barrels.

In China, our PANU project continues to exceed expectations. Field production is averaging in excess of 75,000 barrels of oil per day, with Devon's net share at about 17,000 barrels per day. We began the first of nine additional development wells in early April, and we've also just begun drilling the first of two exploratory wells near PANU, which if successful could utilize the PANU facilities. In Brazil, we're evaluating the economics of potential development options for our 2004 discovery on block BMC8.

During the first quarter, we drilled a third successful well on the block that tested at about 5,000 barrels per day. Devon is the operator of this block in the cam post basin with a 60% working interest and assuming to go forward with development, first production could come on in mid 2007. Finally, in Egypt, the east ZITE C3 exploration well that we mentioned in last quarters call was encouraging on the large but failed to produce that commercial rates.

Also in Egypt, the RAD 1 exploratory well, that's the Raz Abu Derrick (ph) well that we previously mentioned, which is the second well in our joint venture with Santos is underway. Devon is the operator at that well with a 50% working interest. And then that concludes our operations update. Now I will turn the call over to Brian to review the financial results.

Thanks, John. I want to spend a few minutes this morning looking at the key drivers that impacted our first quarter financial results, and more importantly, how these factors are likely to impact our financial outlook through the remainder of the year.

Please note that our first quarter results include revenues and expenses, and capital expenditures associated with the divestiture property. To allow you to better understand the performance and trends associated with our core retained property base, I will highlight both our reported results, and the results attributable to our core retained properties.

Looking first at production, we produced in the first quarter 59.4 million equivalent barrels, or about 660,000 barrels equivalent per day. That was inline with our production forecast range that we had provided in our year-end conference call.

Our first quarter results included 6.9 million barrels of production from our divestiture properties, which was about 400,000 barrels less than we had forecast. Excluding the production contributed by the divestiture properties, our retained properties produced 52.5 million equivalent barrels, or 584,000 barrels per day in the quarter. When you examine the performance of our retained properties in greater detail, you will find that production from our core North American onshore, and gulf properties increased partially offsetting our forecast international production decline.

The decline in international oil production was almost entirely attributable to the Zepheral Field(ph) in Equatorial Guinea. The strength of our onshore results were mapped by the weather impacted drilling results John previously described in Canada.

Looking forward to the second quarter and to the remainder of the year we expect production to grow in our core North American regions. We forecast second quarter production to come in at 56 to 57 million barrels, including an estimated 2.3 million barrels from divestiture properties. This forecast implies a range of 590,000 to 600,000 barrels per day from our retained properties, an increase of 1 to 3% over their first quarter results.

For the year, we remain confident that we will meet our full year, 226 million barrel forecast. That forecast includes an estimated 9 million barrels contributed in the first half from the divestiture properties. Moving to realizations, Larry mentioned in his opening remarks the impact that wider oil price differentials had on Devon in the first quarter. Beginning in late 2004, we experienced a significant widening of market differentials for heavy and sour crudes from benchmark nine Mack WTI (ph).

In the quarter, our oil price realizations came in at or below the bottom of the guidance ranges we provided in all of our producing areas. Consequently, our first quarter company-wide floating realized oil price came in at about 85% of WTI. Please note that our floating realized oil price refers to the price we received for production excluding the impact of hedges.

Our Canadian oil production was hit the hardest relative to our guidance, coming in 2 percentage points below the low end of our forecast range, about 74% of WTI. Although we expect heavy oil prices to show some improvement in the summer as asphalt demand increases, we expect to see second quarter oil price realizations remain near the low end of our guidance ranges.

Our, first quarter price realizations were also significantly reduced by financial hedges. We entered 2005 with about 72,000 barrels per day of our oil production hedged. As a consequence of unwinding hedges associated with property divestitures our hedge position will be reduced to approximately 64,000 barrels per day. That represents about 40% of our expected 2005 oil production, down significantly from our 2004 position, which saw about 70% of our oil hedged. Please note that all of our oil hedges roll off at the end of 2005.

Shifting briefly to natural gas, our first quarter company wide floating realized gas price came in at about 89% of the Henry Hub index price. In the US, our onshore floating gas price realizations were below the bottom of our full year guidance range at 83% of Henry Hub. Conversely in Canada, our floating gas price realizations exceeded the top of our guidance range at 93% of Henry Hub. Despite these variances, the mid point of our guidance produced an accurate overall result. Our natural gas hedge position had almost no financial impact on our first quarter results.

Moving to first quarter marketing and midstream results, our first quarter margin totaled 85 million. This result was right on top of our reported margin in the first quarter of 2004, despite having divested non-core midstream assets in 2004 and early 2005. Looking forward, we remain comfortable with our current full year margin guidance of 260 to 280 million. We are obviously off to a good start on that objective.

Looking at expenses, our reported expense items were generally in line with our guidance. Reported lease operating and transportation expense for both our retained and divestiture property came in at $5.85 per barrel equivalent, that expense included $56 million of expenses associated with the divestiture properties.

The per unit lease operating and transportation expense associated with our retained properties was however, considerably lower than our reported result, coming in at about $5.54 per barrel, right in line with our full year guidance. Our reported first quarter DBNA expense for our oil and gas properties came in at $9.10 per barrel, it's about $0.10 greater than our guidance.

In the second quarter we expect our core retained property DD&A expense to remain at roughly $9 per barrel. Our G&A expenses in the first quarter came in about $8 million below the quarterly rate implied by our full year 2005 forecast. While we remain focused on controlling G&A expenses, we are not prepared at this point to reduce AK guidance.

In the first quarter, G&A was reduced by a $4 million reimbursement. This $4 million reduction in expenses not expected to be repeated in the future periods. I want to spend a few moments reviewing our reported first quarter income tax. As our taxes this quarter included several unusual items.

The net effect of these items was that it increased our reported tax rate at 38% of pretax income and reduced our deferred tax expense to a negative value. These items included $32 million in current taxes resulting from our plan to repatriate $500 million of Canadian earnings to the US and included $52 million resulting from a gain on the sale in the first quarter of non-core midstream assets, and $32 million resulting from gains on the sale of oil and gas properties that closed in the first quarter.

We provided a reconciliation table in today's earnings release that shows the tax effect of these items and other items generally excluded from analyst's estimates. When you back out these items, you get an adjusted current rate of approximately 29%, a deferred rate of 6%, for a total tax rate of 35%, which was right in line with our full year guidance, in summary, a very profitable quarter reflecting the continued execution of our long-term strategy. Before we open up the call to Q&A, I want to comment briefly on our cash position.

As Larry mentioned in his opening remarks our financial strength continues to build. Since quarter end, despite our accelerated repurchase activity, our cash and short-term investment balance remains at $2.4 billion today. Given that we are just beginning to bank the proceeds of the property divestitures, I would expect our cash balance to grow significantly in the second quarter. That enhanced financial strength will allow us to maintain the accelerated pace of our share repurchase program as Larry described. In addition, it provides the flexibility to consider incremental capital investments, accelerated debt repayment, dividend increases and/or expanding our share repurchase activity.

At this point, I am going to turn the call back to Vince. We'll open up the call for Q&A.

Thank you.

Operator, we're ready for the first question.

Thank you. We will now begin the question and answer session.

[Operator Instructions]

Phil Pace with Credit Suisse First Boston, you may ask your question.

Good morning, guys.

Good morning.

Two things. It seemed like the success rate stayed up in Canada quite well despite the increase in activity, is that accurate? And second the BILBO well at 33 million a day in the Deep basin, is there any running room to that particular trend?

Yes, Phil, this is Steve Hadden. Relative to the success rate in Canada yes, that is representative of what the program can deliver, and we expect to continue to deliver. When you get specific in the deep basin and look at BILBO that was a very good opportunity that our team had bought in.

Relative to follow-ups, I think follow-ups of that magnitude, the chance of those are relatively smaller, although they may occur in the future, but we think we will have continued success in the deep basin. That has been an area for growth for us. As you know, we continue to see our volumes grow on a year over year basis, and in the last few years you have seen growth that approaches a double-digit numbers.

It looks very strong. I appreciate it.

One note, Phil, we saw yesterday where you are retiring from the sales side, and I just wanted to say thanks for the good job. We appreciate your matured perspective and candid comments over the years, and we're going to miss you.

Your nice to say that, you won't get rid of me for a few months though.

Good luck.

Thanks Larry.

Our next question comes from Derek Winger of Jefferies & Company.

Mr. Winger, your line is open. Please check your mute button.

Sam Levy (ph) with Done and Rose (ph). You may ask your question.

Good morning, how are you.

Good morning.

Thanks I appreciate it. A couple of question about Barnett Shale, what did you learn from your offset operators particularly on the outside of the core trend? What advantages do you have relative to them and thirdly, there were some announcements talking about one of your competitors about Barnett Shale greatly expanding the gas window outside of the counties of the shale, what are your thoughts on this?

This is Steve Hadden again. As you know, Devon was the first to the play in Barnett Shale through Mitchell energy. And we've continued with that position. We have built a position in Anchorage, about 135,000 acres in the core. When we look at the Barnett and we look at the overall resource, we're very pleased with the position that we have.

We took those positions based on both the economics of those opportunities and the risk of those opportunities relative to the return that they can deliver in our capital program. As we look beyond those areas that we're currently in, we see that the risk and the performance relative to the position that we've established as the lead operator coming in just don't warrant investment in pursuing those at that time in Devon's portfolio. We do understand that there are other people out there trying to expand the play. We wish them all the success in the world but we're very pleased with our investments with our position, because we think they're going to give us the best return.

Did you talk about increasing the pace of drilling the play? What has been the change in your view? What is causing you to do this?

When we look at the play, we see, obviously, both the core, where we had quite a run of success and quite a bit of drilling in the past years, and we have the non-core where you see it is accelerating into that exploitation play. What we see is continued acceleration.

We are going to drill 100 wells or more, horizontal wells in the non-core area. We've also acquired a thousand square miles of seismic and have continued to process that seismic, do the reservoir work, and move into the play in a way that we think we will give us the best returns for our dollars. So what you'll see is, you'll see us accelerating into the non-core area, and I think John has mentioned in his comments that in this next quarter, we're looking at that acceleration, and we'll have some news for you probably in the second quarter conference call about that.

And finally, given your gathering system within the play, as you increase your pace, does that have any impact on the other players in the play?

Yeah, this Darryl Smette. Obviously there has been a lot of activity in the basin. With that as a result in increased volumes available through Devon's midstream transmission we have sufficient capacity to move our gas and get some other people in the area. As we move the gas out of the basin, we have the lot of long-term firm contracts for transportation, and also from contracts with downstream users of gas. So we think we're very well positioned not only for the volumes, and we have now, but for the increased activity that John and Steve talked about earlier on.

Great. Okay, thanks, guys.

Avon Molkanov (ph) of Raymond James. You may ask your question.

Avon Molkano Thanks very much. Question about your dividend, given the large cash positions are there any possibility you might, you know possibly have a one-time dividend or just increase the quarterly dividend, either way?

This is Larry. As I said, we doubled it a year ago, and we have increased that by 50% in the first quarter this year. I don't think it's likely that we have a big one-time dividend in terms of using surplus cash of that magnitude. We think a share repurchase program makes more sense. We're certainly confident, but if we continue in this economic environment, that we will see further dividend increases in the future.

Thanks.

Bob Christensen of Buckingham Research. You may ask your question.

Bob Christensen, Buckingham Research. Thank you. Just a little more on your horizontal wells in the non-core area, what are they IP-ing at, and what is the estimating ultimate recovery, and what is the cost running, and how deep are they, and how long are the laterals? Thanks.

Okay, Bob, just a few things. As we go into the non-core, what we typically see in the non-cores is our IP's range from 1 to 4 million a day. We expect to have an average of about 2.5 million a day. Obviously, as we're moving into the areas of the non-core in Johnson County and Harper County, Wide County, we expect to see some of those results that continue to improve, as we apply our knowledge about the play as we accelerate into it.

The average well cost on those horizontal wells runs about $2.3 million. When we look at our average recovery, that's about 1.5 BCF equivalent in our current view. The wells run about 10,000 feet or so in depth, and the length of the horizontal section varies a bit depending on where we are. I think that covers most of the questions on the horizontal wells.

As you can understand, as we move into the non-core area, there are different challenges that we're looking at. Having the ability to have that thousand square miles of seismic and having the knowledge of reservoirs that we have gained allows us to kind of customize where we position the wells, the length of the horizontal wells and the completion methodologies to try and deliver the best results we can, but we're pretty much staying with those averages for now, and those wouldn't change. We will probably comment on that in a subsequent call.

Just when you say the laterals vary are they 1000-foot laterals, 2,000-foot laterals, and how many intervals are you hydraulically factors stimulating? Thanks.

The intervals are longer than the 1000 feet basically. We are quite a bit longer in some cases. I can't tell you right now how many intervals we are actuating, but I will mention it to Vince. He has that information.

Thank you.

[Operator Instructions].

We have no further questions in the queue. So, I guess do you have any closing comments, Larry?

Well all in all, we think it was a very good quarter. We're very sorry to miss the earnings estimates that was really caused primarily by the differentials and that is really a short-term phenomenon. If you look at the long-term results, we are achieving with. The drilled wells are very encouraging both with the development of wells, and the exploratory wells we're drilling. We are more than pleased with the success we've had with our disposition of the properties we chose to sell both in midstream area and the property base substantially improves our portfolio.

We're delighted and we have been able to get that done at the right time in the market and achieve the results that we have. We're happy with the shares buyback program. So I think we're executing on the plan that we've described in the past.

All in all, we're happy with the quarter. Thanks very much. That ends today's call.