德文能源 (DVN) 2006 Q2 法說會逐字稿

Welcome to Devon Energy Corporation second-quarter earnings conference call. At this time all participants are in the listen-only mode. After the prepared remarks we will conduct a question-and-answer session. (OPERATOR INSTRUCTIONS). This conference is being recorded. 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 Communications and Investor Relations. Sir, you may begin.

Thank you. Good morning, everyone, and welcome to Devon's second-quarter 2006 conference call and webcast. I will cover a few compliance items and then turn the call over to our Chairman and CEO, Larry Nichols. He will highlight our quarterly results and then our President, John Richels will review operating results and finally, Brian Jennings, Devin's CFO will cover the financial highlights and provide you some updated guidance for the second half of the year. Following Brian's comments we will open the call to questions, and as is our practice we will limit the call to about an hour. So if we don't get to your question feel free to phone us later today.

We will be filing a form 8-K later today with updated guidance. We will email that information to those of you that are on our contact list once the filing is confirmed with the SEC. That form 8-K with the updated guidance will also be available on our website.

In today's call we will be discussing our plans, forecasts, estimates and future operating results. This information is considered forward-looking statements or are considered forward-looking statements under the U.S. securities law. And while we always strive to provide you the very best estimates that we can, there are many factors of course that could cause our actual results to differ from those in our estimates. You are encouraged to review the risk factors discussion that is provided with the forecasts and our SEC filings.

One final compliance item, we will make reference today to certain non-GAAP performance measures; when we use these measures we are required to provide certain related disclosures. Those disclosures are now available to you on our website. At this point level I will turn the call over to Larry.

Thanks Vince and good morning everyone. Second quarter was another very, very solid one for Devon. We reported net earnings of $859 million, which is a 31% increase over 2005. Our reported earnings per share climbed to $1.92, which is nearly 40% above second quarter '05 results. This reflects not only a very solid operating performance, but it also is enhanced by the impact of our share repurchases. You may recall that we repurchased approximately 10% of our outstanding stock since late 2004.

Second quarter earnings per share when adjusted for items that are generally excluded in the First Call estimates were $1.57 or just above First Call. Cash flow before balance sheet changes reached $1.5 billion in the second quarter, a 19% increase from the second quarter of last year, and 13% above the First Call estimates. Production was right in line with our guidance at 52.6 million equivalent barrels. This translates to 578,000 equivalent barrels per day which is up 2% from just the first quarter of this year.

Also during the second quarter we announced and closed our $2.2 billion acquisition of certain properties from Chief. This acquisition reinforces Devon's leadership position in the Barnett Shale in North Texas. This is of course the largest gas field in Texas and is one of the fastest-growing natural gas fields in the continent. And while Devon was already by far the largest and most active operator in the play, the Chief assets add approximately 2000 undrilled locations which increases our net unrisk potential in this field to more than 13 Pcf of gas equivalent. That is roughly the same size of Devon's existing reserve, so it is a very significant potential resource for us. The consolidation of the Chief assets in our Barnett Shale operation is going very smoothly. It of course is a relatively straightforward process to consolidate a concentrated asset position of this type in an area where we already have a very high level of operating expertise, a very large and talented workforce and well-established relations with vendors, regulators and all the other stakeholders with whom we do business.

With the addition of the Chief assets we are now running 25 rigs in the Barnett and have more than 2500 producing wells. By year end we expect to be running 30 rigs and a targeted 2006 exit rate of 710 million cubic feet of gas per day net to Devon's interest. We are both increasing our previous exit rate for the historical Devon Barnett assets to 640 million a day, and then adding 70 million per day that we expect from the Chief assets. So this is the highest forecast we've ever come out with for Barnett for the end of the year.

Today we are also increasing our full-year production forecast by 1 million equivalent barrels to 218 million BOE. This is being driven by an earlier than expected payout on the ACG field in Azerbaijan. As a refresher I will remind you that Devon has a 5.6% carried working interest in ACG, which is a 5.5 billion barrel field in the Caspian Sea. Current production averages over 50,000 barrels per day, and several wells have had initial production rates of in excess of 30,000 barrels per day. That is per well. The field is being developed in several phases. The most recent phase to begin production is West Azeri, came on in early 2006. The East Azeri facilities were recently installed and hooked up and commissioning is underway with first production expected at the end of 2006. East Azeri will ultimately increase gross production to approximately 260,000 barrels per day.

Phase III, which is the Deepwater Gunashli area is under construction and is expected to begin producing in 2008. Ultimately ACG is expected to produce in excess of 1 million barrels per day. Most of Devon's share of ACG production in the past has gone to repay our partners for capital costs they incurred on behalf of Devon under the terms of our agreement. Under previous 2006 forecast assumed the payout would not occur in 2007. However, given stronger than expected oil prices this year we are now looking for payout in the second half of 2006. At this pointed Devon's share of ACG production will ramp up quickly to about 30,000 barrels per day.

To achieve the 218 million BOE companywide forecast for 2006 that we are now providing today in this call we are looking for third-quarter 2006 production to climb between 55 and 56 million BOE. This represents a 5% to 6% increase over second quarter production, which of course was 2% above first quarter. In the fourth quarter we expect production to climb further to between 58 and 59 million BOE. This leads right into the strong production growth that we expect for 2007. To give you more details on that I will turn the call over to the John Richels.

Thank you, Larry and good morning everyone. Let's start with a look at our 2006 capital spending. Based on our midyear capital review we are increasing our 2006 drilling and facilities budget by a little more than $300 million to about $4.8 billion. About half of the increase is due to cost inflation. The other half is related to the early payout of our interest in the ACG field and higher activity levels on a couple of other projects. As Larry said we now anticipate payout of our ACG field in Azerbaijan to occur later this year rather than in 2007. As a result, we expect to pick up about $65 million of additional capital expenditures in 2006 related to our ACG working interest.

Before I cover the quarterly highlights I want to speak briefly to our outlook for finding costs. When you add slugging and abandonment costs, capitalized G&A and capitalized interest to our updated drilling and facilities budget, you will find that we expect to spend between $5.1 and $5.3 billion of capital this year. The associated reserve additions are expected to be 420 to 450 million barrels, generating what we believe are very attractive finding and development costs. However, because $1.2 billion of the purchase price of the Chief assets is allocated to undeveloped acreage, the calculation used by most analysts will reflect $6.3 billion to $6.5 billion as the numerator for calculating drill bit F&D. This will add almost $3 per barrel to reported 2006 drill bit finding and development costs.

Turning now to the second quarter, capital expenditures for drilling and facilities were roughly $1.1 billion. At the end of the quarter we had 137 rigs running companywide with 71 rigs drilling Devon operated wells. We drilled 546 wells companywide during the quarter, 53 of these wells were classified as exploration wells, of which 89% were successful. The remaining 493 wells were development wells and about 98% of those wells were successful. So the second quarter was another very active and very successful one with the drill bit.

Moving now to some area by area highlights, I will begin the operational highlights onshore with the Barnett Shale field in North Texas. As Larry mentioned on June 29, we announced the completion of our Chief acquisition. The Chief asset significantly increased our already large presence in the Barnett Shale to what is now over 733,000 net acres and opened the way to acceleration of our drilling activity in that area. We currently have 25 operated rigs running in the Barnett, 7 are operating in the core area and 18 are running outside the core, including 6 in Johnson County. The first of 10 new high-efficiency drilling rigs, that Devon has on order initiated drilling operations in late July. We expect the remaining 9 rigs to be delivered between now and the end of the year as we replace older rigs and ramp up our fleet to 30 Devon operated Barnett rigs by year end.

During the second quarter we completed a total of 80 Barnett wells of which 31 were in the core and 49 were outside the core. Devon's net Barnett Shale production averaged a record 588 million cubic feet of gas equivalent per day for the month of June, with about 114 million cubic feet per day coming from outside the core. We continue to see encouraging results from our core area 28 for infill drilling program; through the end of the second quarter we have drilled a total of 54 infill wells, 37 of the infill wells are horizontal and 28 of those have been tied in. Initial per well production on these 28 wells has averaged 2.4 million cubic feet per day. The latest 28 or horizontal infill well results continue to support our 2 Bcf per well average for horizontal infill recoveries. While most of the 20 are infill wells or horizontals that cover as many as four 20-acre locations, we do drill 20-acre vertical wells in places where we can't fit in a horizontal.

At the end of the second quarter we had 68 wells that were awaiting connection to the producing grid. This includes 28 wells from the Chief acquisition that we acquired just the day before the quarter ended. Most of these wells are in Johnson and Parker Counties were existing gas gathering infrastructure was limited. We expect to bring most of the 68 wells on in the next few months, which will result in the significant boost to our Barnett Shale production that Larry alluded to earlier.

In the Arkoma Basin shale play we added to our acreage position in the second quarter, bringing our total to about 98,000 net acres. We are concentrating our efforts in the Woodford Shale portion of the basin where we continued to evaluate our acreage and work to optimize location selection and completion techniques. Although our results are still preliminary, we are increasingly optimistic that this play could deliver up to a Tcf net to Devon's position.

In the Rockies we recently completed a joint venture in the Montana Overthrust Belt that brings Devon a 50% interest in 213,000 net undeveloped acres of land. We have extensive experience in this play in the foothills of Canada, including at our Coleman field in southwestern Alberta, which has ultimate recoveries in excess of 400 billion cubic feet of gas. We have begun acquiring seismic over the Montana acreage and plan to drill a first exploratory well late this year or early in 2007.

Moving to East Texas, we added a sixth rig in the Carthage area. In the second quarter we drilled 21 wells and continued an active recompletion program. Year-to-date we've drilled 45 of the 104 wells that were planned for 2006. Our second quarter net production from Carthage increased to 233 million cubic feet of gas equivalent per day, which is up 5% from the first quarter. Just to the southwest of Carthage we have 125,000 net acres in the Groesbeck area of East Texas. This area produces from Cotton Valley and Bossier formations. And we continue to see outstanding results from the horizontal wells that we are drilling there in the Nan-Su-Gail field. We drilled two 100% working interest wells during the second quarter including the [Hill 9H] well that had initial production of 26 million cubic feet per day. This well produced over one Bcf of natural gas in the first 70 days of production. As a result of the success we've had there we have expanded our 2006 program to 6 wells, and believe we may have as many as 10 additional locations at Nan-Su-Gail.

We now have three rigs running in the Groesbeck area that are both drilling horizontal wells at Nan-Su-Gail and also testing the concept in other fields. If successful in these other areas we could have up to 60 additional locations to drill. Groesbeck is one of the areas that is contributing to the increase in our 2006 capital program.

Moving east in North Louisiana we have over 200,000 net acres at our prospective for Bossier production. We've talked about this a little bit in our last call and we have defined seven separate prospect areas with accumulative unrisk resource potential of more than 2 Tcf of natural gas next to Devon. In last quarter's call we mentioned the Devon operated Spillers 18-1 well that we drilled in the East Vernon prospect area. After completion of the fourth and final frac stage of that well, the well flowed at a peak rate of 16 million cubic feet per day. However, it produced quite a bit of water so we're currently testing individual sections of the well in an attempt to eliminate water intrusion. The first appraisal well to the Spillers discovery was spud during the second quarter. This well, it is called the Warehouser 13-1 well logged 131 feet of pay in the Bossier with greater than 4% porosity. We are now fracing the first of four stages and should have results in our third-quarter call. Devon has a 50% working interest in these two East Vernon Wells.

Also in the North Louisiana Bossier trend the initial exploratory well on the Mount Moriah prospect that we mentioned last quarter logged 60 feet of pay in the Bossier and produced at a peak rate of 5.5 million cubic feet per day. We are encouraged by this result, and we're currently processing 3-D seismic data over the area to assist with future location selection. Moving to Canada, now that things have dried out a bit, our summer drilling programs are well underway in most areas. At the end of June we had 18 rigs running in Canada including 11 operated by Devon. This is up from 6 rigs running in April of which 3 were Devon operated. Our Lloydminster oil play in eastern Alberta continues to be an active area for us. This area includes our Iron River acreage that we acquired in 2005. We plan to drill over 350 wells in the region this year. Extremely wet conditions in the second quarter delayed our drilling, but we now have 7 rigs running and plan to stay at that level for the rest of the year. At our Jackfish thermal heavy oil project in eastern Alberta facilities construction and drilling continue to move forward as planned. Because we contractually fixed the cost of a lot of the surface facilities and because this is a SAGD project, as opposed to a mining project, we have not experienced the big cost overruns that have been in the headlines for some of the oil sands mining projects. Through the second quarter we've drilled 13 horizontal well pairs, and we plan to drill at least 6 additional well pairs this year. I'll just remind you that Jackfish is a 300 million barrel project; we plan to begin steaming in mid 2007 and expect to reach full production of 35,000 barrels per day in 2008. Devon has a 100% working interest in the project and construction of the related access pipeline between Jackfish and Edmonton continues on schedule.

Finally, we plan to submit an application for regulatory approval of Jackfish 2, a 300 million barrel Jackfish look-alike project that is directly adjacent to our Jackfish lease in the fall of 2006. Turning to the Gulf of Mexico, efforts to restore the remaining production suspended by last year's hurricanes are ongoing. The Redhawk gas field came back online in May at about 10,000 equivalent barrels per day net to Devon. In early July we restored about 6,000 additional barrels of daily production from the Eugene Island 334 and West Cameron 165 and 291 fields. With these fields back online about 90% of our prehurricane Gulf production has been restored.

In eastern Gulf of Mexico both sidetrack wells have been drilled on the Merganser field in the Atwater Valley area. First production is expected in second quarter of 2007. Merganser will produce into the Independence Hub at about 50 million cubic feet of natural gas per day net to our interest.

Moving to deepwater Gulf exploration, the production test on our Jack discovery in the lower tertiary trend concluded in mid-June, and we're currently evaluating the test data. The Jack test results are the first-ever from a well drilled to the lower tertiary in the deepwater Gulf. The data from this test has considerable commercial value and far-reaching implications beyond the Jack project. We expect to be able to report the results of the Jack production tests later in the third quarter. I will just remind you Devon has a 25% working interest in Jack, and it is one of three Devon discoveries in the lower tertiary trend.

Also in the deepwater Gulf drilling has been completed on the BP operated Kaskida well on Keathley Canyon 292 and the partners are currently evaluating the data. Devon has a 20% working interest in Kaskida. In our deepwater Miocene program we're currently drilling below 13,000 feet on the Caterpillar prospect which was spud in late June. Caterpillar is a 28,000 foot subsalt Miocene test on Mississippi Canyon 782. This exploratory well is operated by Chevron and offsets Chevron Blind Faith discovery. Devon has a 25% working interest in the prospect.

Finally, moving into international, starting in West Africa with our operations offshore equatorial Guinea fieldwide production at our Zafiro field is currently over 235,000 barrels of oil per day following some down time due to unscheduled maintenance on the FPSO. Devon's net share production averaged 33,000 barrels per day in the second quarter. As expected, we should reach the final cumulative production threshold during the first quarter of 2007 when the contractors profit share drops from 60% to 50%. Our interest in Zafiro is stable from that point forward. Also in equatorial Guinea in the third quarter we plan to initiate a 3 well program to evaluate our 2005 Venus discovery on offshore block P. On our Panyu project in China where we experienced the riser leak that we mentioned last quarter, we have restored gross field production to over 60,000 barrels of oil per day and Devon's net production share to about 15,000 barrels per day. We are also having good success with delineation drilling of Panyu which extended the field boundaries by one to two kilometers to the Southwest.

On the exploration front in China we will begin acquiring 3-D seismic on the Devon operated block 4205 in the South China Sea this month, leading up to a test well in 2007 pending rig availability. Block 4205 in which we have a 100% working interest is adjacent to block 2926 where Husky recently announced a 4 to 6 Tcf gas discovery. In Brazil our Polvo development project on offshore block BMC8 is proceeding ahead of schedule causing us to accelerate about $30 million of capital expenditures into 2006. In June the drilling deck was lifted into place and initial drydock work on FPSO was completed. Design work continues on the FPSO mooring system installation. I will remind you that Polvo is a 50 million barrel project that we believe has considerable additional resource potential. In the third quarter we will initiate a 3 well exploratory drilling program to attempt to expand development to other parts of the block. We expect first production from Polvo in mid 2007 and have designed our facilities to handle additional volumes should our future exploration program prove successful.

And as a final note, the exploratory well on block BMC32 in Brazil that we mentioned in our first quarter call was not commercial. That concludes our operations update. Now I will turn the call over to Brian for a financial review.

Thanks, John. I want to take you through a brief review of the key drivers that impacted our second quarter financial results. In addition I want to review with you how these factors are likely to impact our outlook for the second half of the year. As Vince mentioned in his opening remarks, we plan to file a form 8-K later today detailing updates to our 2006 financial guidance. Looking first at production, in the second quarter we produced 52.6 million barrels of oil equivalent. That is about 578,000 equivalent barrels per day. This result was just above the midpoint of the production forecast we provided to you in our first quarter conference call.

For those of you comparing our reported results to last year's second quarter please note that our second quarter 2005 results did include production from properties we later divested. In addition, we continued to defer in the quarter volumes related to hurricane damage sustained last summer in the Gulf of Mexico and volumes related to the production riser repair at our Panyu field. Consequently due principally to these deferrals, second quarter production from our retained property base was lower on a year-over-year basis. However, on a sequential quarter basis our production increased 2%. That growth was driven by strong performance across all our operating areas.

The impact of early payout at our ACG field is expected to add 3 million barrels to our second half production. However, we are only increasing our annual production forecast by 1 million barrels to 218 million barrels for the year. We expect the impact of higher oil prices on our international production sharing contracts to reduce reported volumes principally at Panyu and Zafiro, by approximately 700,000 barrels equivalent. In addition, unexpected downtime at Zafiro, delays restoring Panyu to full production and reduced production in Egypt lowered our international production outlook by an additional 1 million barrels equivalent.

Looking forward in the third quarter we expect production to increase 5% to 6% above our second quarter results coming in between 55 and 56 million barrels equivalent. In the fourth quarter we now expect to produce between 58 and 59 million barrels equivalent as we build momentum into 2007.

Moving now to price realizations, during the second quarter the WTI benchmark price rose to $70.64 per barrel. That is a 33% increase over the second quarter of last year. In addition to higher benchmark prices, oil differentials narrowed in virtually all of our producing regions. This included a significant improvement in Canadian heavy oil pricing. As a result of these narrowing differentials our oil price realizations exceeded our guidance in all areas except for the U.S. onshore. We will be updating our differential guidance in today's 8-K to reflect these improvements.

On the natural gas side the benchmark Henry Hub index averaged $6.80 per Mcf in the second quarter. Companywide price realizations were at the top end of our guidance at 86% of Henry Hub, an improvement over the 79% we reported in the first quarter. Looking ahead to the third quarter, we expect natural gas price realizations to approximate 100% of NYMEX for the Gulf, 80% of NYMEX for our U.S. onshore volumes and 85% of NYMEX for Canada.

Turning now to our marketing and midstream business, once again our marketing and midstream results were very strong. Our operating profit for the second quarter totaled $109 million, a 17% increase over our second quarter 2005 results. Based upon our first-half results, we now expect our marketing and midstream full-year operating profit to come in between $420 and $440 million. This represents an increase of $50 million over our previous guidance range.

Before I move to expenses I want to update you on the status of insurance recoveries related to last year's hurricane season. As a reminder these recoveries are not booked as oil and gas revenue but rather are netted against related costs with the excess booked to other income. We expect to recognize in total approximately $150 million of other income due to hurricane recoveries in excess of related costs. We had forecast that we would recognize $50 to $70 million of this total in 2006 with the balance recognized in 2007. We now believe that we will recognize the entire $150 million amount of other income in 2007 when we expect to have a full and complete accounting of the actual repair costs. We did receive $467 million in the third quarter from our insurers related to damages and business interruption coverage. We expect to recover additional amounts later this year and in 2007. The delay in recognizing the income attributable to our insurance recoveries until 2007 will reduce our forecast of other income for the last half of this year. We now expect other income in the second half of 2006 to total $22 to $42 million.

Shifting to expenses, lease operating and transportation expenses were in line with our guidance coming in at $362 million or $6.87 per equivalent barrel. Despite the impact of the strengthening Canadian dollar, hurricane downtime and industrywide cost pressures, our costs remained on a BOE basis essentially flat with the first quarter of 2006. Looking ahead we anticipate lease operating and transportation expenses in the second half of the year to remain within our previous guidance range.

Our production taxes for the quarter came in at $86 million. That is about 3.9% of our oil and gas revenues. This was outside of our forecasted range of 3.25 to 3.75% of sales. This was driven by a change in the tax regime in China enacted during the second quarter. To reflect this change we are adjusting our production tax forecast to a range of 3.6% to 4.0% of oil, gas and NGL revenues.

Second quarter DD&A expense came in at $10.56 per equivalent barrel. This was above our guidance range of $9.90 to $10.30 per equivalent barrel. This variance is almost entirely attributable to the impact of rising service and supply costs on development costs and estimated future development costs. For the third and fourth quarters we expect our DD&A rates to be between $10.60 and $10.80 per equivalent barrel of production.

Our reported G&A expenses were in line with our guidance at $90 million; G&A expenses in the quarter were essentially flat with the first quarter. Year-to-date our G&A expenses have run below our full-year forecast. However, with the impact of the Chief acquisition and general industry cost pressures we expect G&A to run approximately $100 million per quarter for the remainder of the year. Accordingly, we are maintaining our full-year G&A guidance of $370 to $390 million.

Interest expense for the second quarter was in line with our guidance at $102 million. Looking forward, we anticipate interest expense in the second half of the year to increase to between $115 and $120 million per quarter as a result of the debt incurred to fund the Chief acquisition. The next expense item I will cover is the line item entitled "change in fair value financial instruments." We don't provide forecasts of this non-cash item, and most analysts don't include it in their numbers. This item results from a convertible debenture we have outstanding and our ownership of 14.2 million shares of Chevron stock into which these debentures are exchangeable. As the price of Chevron stock fluctuates, we are required to adjust the recorded liability to reflect the change in value of the option embedded in the debentures. In the second quarter the value of Chevron stock increased and consequently we were required to recognize a $47 million non-cash charge.

Moving to income tax expense, our reported income tax for the quarter came in at 18% of pre-tax income. However this included some out of period items. First, we received a $243 million deferred tax benefit in Canada due to a reduction in statutory tax rates. This benefit was partially offset by a $39 million non-cash charge related to a change in Texas tax regulations. When you adjust our reported taxes for these two items, you get an adjusted current rate of 18% and a deferred rate of 19%. For a total tax rate of 37%. Even though the second quarter split occurred and deferred taxes was out of our range our year-to-date results were right in line with full-year guidance. Looking forward we believe that our guidance remains valid for the second half of the year.

Moving to the bottom line, net earnings for the quarter were $859 million, a 31% increase over the second quarter of last year. Our earnings per share adjusted for items that analysts do not forecast were $1.57, which is just above the First Call mean of $1.56 per share. As is customary, we are providing a reconciliation table in today's earnings release which shows the effects of items that are generally excluded from analysts estimate.

Before we open up the call to Q&A, I want to spend a few moments reviewing our financial position. In the quarter, cash flow from operations before balance sheet changes totaled just over $1.5 billion, up 19% over the second quarter of last year and 3% greater than our first-quarter results. Looking at the first six months of the year we generated operating cash flow before balance sheet changes totaling $3 billion while funding $2.7 billion of capital investment, allowing us to generate $300 million of free cash flow before the Chief acquisition.

Looking briefly at our capital structure we began the second quarter with cash and short-term investments of $2.2 billion. We utilized cash in second quarter operating cash flow to fund $1.4 billion of capital expenditures and to fund $700 million of the $2.2 billion acquisition of Chief. Utilized commercial paper borrowings to finance the balance of the Chief acquisition increasing our debt balance in the quarter by about $1.4 billion. Despite the increase in leverage we continue to maintain a high degree of financial flexibility. We ended the quarter with cash and short-term investments totaling $1.4 billion. While our net debt to adjusted capital ratio increased to 26% during the quarter, with the Chief acquisition, we expect to reduce this ratio to approximately 20% by year end. Our pre-Chief level. Before going forward we expect to utilize our free cash flow to repay our short-term borrowings, continue to redeem maturing debt and when appropriate resume the repurchases of our common stock. With that I am going to hand back the call to Vince to open up for Q&A. Thank you.

Operator, we are ready to take the first question.

(OPERATOR INSTRUCTIONS) Ben Dell, Sanford Bernstein.

I guess I have a couple of questions. My first is on probably for Brian looking at the cash flow versus CapEx. Year-on-year organic CapEx is up as far as I calculate at 35%, 35.6%. And you talked about 300 million of free cash flow obviously excluding those balance sheet changes (inaudible) including those would be slightly less. Going forward what are your assumptions in terms of your free cash flow generation to pay down these acquisitions? Are you assuming that the commodity stays up or goes higher, are you assuming cost inflation basically stops or are you planning on funding future CapEx as far as Devon off the balance sheet if that is what is required?

There is a couple of questions in there. We, as John outlined, we did announce today an increase in our capital budget; components of that included some cost pressure, but mostly the increase was attributable to investments in our business. So we are pretty pleased with the results. In fact, if you look at our guidance for the year most of our cost items have remained right where we thought they would be at the beginning of the year. Looking to the next six months of the year and what we plan to do with cash flow, we financed the incremental part of Chief using commercial paper. We did that because we recognized we have the financial flexibility to rapidly repay that. The pace of which we repay that is going to be driven by where natural gas prices go in all honesty over the next six months. 60% of our production is natural gas. We have tremendous cash leverage to where that price ends up, but we do expect to generate over the next six months more cash flow than we will be consuming in our investments. So where we end up year end I think at this point we will be driven by where gas prices go in the next six months.

And when you look at CapEx in '07 are you assuming that is going to be flat in '06, or up or down?

We haven't put out an '07 capital budget at this point, and of course that is opportunity driven as well as driven by the circumstances that we see when we go through our capital budget process near the end of the year.

And just two clarification questions. On your reserve estimate that you gave will that include any bookings from the Jackfish II? And if so, how much?

Nothing from Jackfish II, we have an additional reserve booking in 2006 from Jackfish I, that is quite a bit smaller than what we previously booked. But Jackfish II wouldn't be booked until we put a spade in the ground which is a couple years out at least.

Okay, great, and lastly can you just confirm whether or not you are bidding on Anadarko's Canadian assets?

I'll answer that. We don't discuss what we are looking at and not looking at. But if you put that in the context of what we said in the past that we are very happy with the assets that we have, we look for opportunities like Chief where you can be very accretive and add on existing areas.

I guess I will take that as a no, then.

Operator, we are ready to take the next person in the queue.

John Herrlin, Merrill Lynch.

Some quick unrelated ones. You mentioned the tertiaries so the obvious question is when will we hear more information about Jack post-lease sale, you said third-quarter, John?

Yes, we should have some results -- we're expecting to have some results in the third quarter that we can announce.

We're still working on really examining and refining the data that we've collected. And so it will take us a little while before we have any kind of definitive results that we can announce, John.

Okay, next one for me is ACG. How much will it run in 2007 ballpark? Cost wise?

Are you asking what the capital expenditures are going to be in 2007?

Exactly.

I think it is going to run about, roughly about $130 to $150 million for the year.

Next one, will the Barnett Shale with the new rigs, how much drilling time do you cut down? And what is your overall spud to tie in times of the wells you drill?

We are running -- we've gone down from about 33 days down to 18 days in our drilling time, with those higher efficiency rigs as we move forward, and that is from last year into this year as we look at that. And the way we tie in our wells generally on average we drill about this year -- we will drill about 350, 360 wells on the operated side. And the way we work it is generally in the areas where we have the large trunk lines in place we hook them up relatively quickly. In other words, we will drill the well, complete the well, already have the line laid as soon as we do the stimulation, we will then actually test into the line. So that is relatively quick.

Some of the new areas that we are moving into we are laying much larger trunk lines. I think they are about 20-inch trunk lines, and we just simply build that infrastructure and then do the same thing. So that takes a little bit longer leadtime to put that in and that is why you saw some of the inventory that we had where we had some wells waiting on a hookup to get that done. But in the context of drilling the 350 wells, we're not too concerned about that.

Last one for me is on Polvo. What is the gravity of the oil?

That gravity is running about 24 to 26 degrees and a sulfur content of about 1.5% to 2%.

Thanks a lot.

Ellen Hannan, Bear Stearns.

A follow-up on ACG. Brian can you tell us when this starts to flow through your income statement next year what impact will that have on your LOE and/or your DD&A rate?

On the LOE point recognize that these are very low-cost barrels, so on average every barrel we add from ACG is going to bring down our LOE, so that is all good news. And on the DD&A rate we haven't given guidance for next year but it would have in our view the same favorable effect. But recognize that is a part of our business and the DD&A rate is going to be really driven by the capital investments we're making. We're making 4 billion this year as John just discussed, an increase this year. But that is really going to be much more impacted by the magnitude of our capital budget than ACG.

Okay. Thank you.

(OPERATOR INSTRUCTIONS) Simmons & Co., Tom Gardner.

Given the recent natural gas price softness is there any discussion of potentially altering Devon's current philosophy on commodity hedging?

Current market conditions are we considering altering our strategy on commodity hedging? Larry you want to take that question?

No, I don't think there has been any change in our view. That of course can change as the extent to which you can lock in hedges widens but because of our low-cost structure, because of our low debt we just don't see any other risk factors there. In our balance sheet, the balance between oil and gas that we have that really compel us to lock that in in order to secure our capital budget. We just don't really see the need to do that. Obviously we could be opportunistic, but we certainly don't have any compelling need to do that given where we are.

And one last question, could you give us an update on where you are with regard to storm related insurance in the Gulf?

You are asking for an update on storm related insurance in the Gulf, are you talking about prospectively or the recoveries that Brian talked about in the call?

Prospectively.

Obviously the impact of last year's hurricanes were significant to the insurance business; in general rates in the Gulf have significantly increased in particular for what is defined as named windstorm damage. We were very careful in securing additional coverages, but in all cases the cost of insurance in the Gulf has gone up. One aspect of insurance that has got much different is secure in the Gulf has been business interruption insurance and importantly the structure of business interruption insurance. But it's part of our business'; we're in it every day, and we feel what we have in place today going through next year is very, very competitive in this market.

Thank you, gentlemen. Good quarter.

Seth Glickenhaus, Glickenhaus & Company.

I just want to congratulate you fellows on a very fine quarter, and I was curious overall about your hedging. What percentage of your output do you feel is hedged? Both in gas and in natural gas and in oil?

At this point it is essentially zero of our oil and gas is hedged. In past years when we had higher debt we were 50% hedged, but for 2006 and going forward we really don't see the need for us to do that. So at the moment we are zero hedged.

Thank you ever so much. I think that's great.

David Heikkinen, Pickering Energy.

A question on the three discoveries in the lower tertiary trend. Can you remind us had you booked reserves to those? They were contingent upon the Jack test. And then the inventory of exploratory prospects that you have on the books targeting lower tertiary?

No, we have so far booked no reserves from the oil tertiary and at this moment are not forecast to book any this year. So those are not in any of the numbers that John gave you earlier. With regard to the inventory we have built up a very significant inventory out there, which is really pending the results of Jack and some of the other -- the Jack test -- and some of the other drilling in the area is a potential major resource for this Company.

And the three discoveries is that St. Malo, Jack, Cascade? I had Trident down, as well. I just wanted to make sure I was reconciling the three discoveries that you were mentioning, John.

Yes, those are our three discoveries.

I counted four. The Jack, St. Malo, Cascade (multiple speakers)

You are correct that we have a small interest in Trident. I don't think we consider it to be a stand-alone commercial discovery at this point.

That was it. Thanks guys.

Gil Yang, Citigroup.

Could you comment on your thinking about the best way to monetize the value or capture the value of the Jackfish oil, whether it is to sign a downstream integration agreement or just to sell the heavy oil?

Darryl, do you want to handle that one?

Yes, I'll handle that one. As you probably know, Gil, we are putting in place the access pipeline to move not only (indiscernible) up from Edmonton to Jackfish project but to move the blended stream down. We are continuing discussions with a number of different parties, both for a (indiscernible) supply right now, it looks like we are going to start out using condensate. And then also markets downstream for the blended stock. Those negotiations are going on with a lot of different parties right now. We have not settled on a decision on where we would either buy the condensate or sell the blended crude or to what refineries or what other entities. But those discussions are ongoing, and it is our hope that we will make a decision on that probably by the end of the third quarter, but more likely will be towards the end of the year.

Gil, our enthusiasm only grows as we see more and more companies in the refining sector look at installing upgraders or revising their refineries, so we think we know we have several options, and seeing the need as we said for a long time and certainly don't now see any need to build our own or enter into any kind of partnership relationship. We just haven't seen the need to tie up our capital that way, and that belief only grows.

And added to that, of course, we've seen some reversal of pipelines flowing gas from North to South that actually can go all the way to the Gulf Coast now, and there is a number of projects that suggest that that capacity will only increase. So the activity level is strong, and so as Larry said, we are very, very comfortable with how that market is developing.

You find that the discussions -- is your phone ringing more, or are you making outbound phone calls more for the setting of those meetings?

It's both. We are very active -- we just tend to be very active on the marketing of the midstream sites; we're very active doing it. But we also get a lot of calls from refiners, pipeline companies, upgraders, the list is very, very long.

Okay. Thank you.

(OPERATOR INSTRUCTIONS)

At this point we don't have any further questions in the queue, so Larry do you have any closing remarks?

We're now at the midpoint of the year, and we think our first six months are a very solid performance; year-to-date reported earnings per share are 37% ahead of last year. Cash flow before balance sheet changes is up almost 30%. Our North American assets, the core of our business, continue to deliver reliable and profitable results. The Chief acquisition will provide another leg of drilling opportunities in production growth in the Barnett Shale, increasing both our 2006 and our long-term production growth outlook. An important contributor to our long-term production growth, ACG field is now coming on ahead of schedule. All of this has led us to increase our full-year production forecast by one [billion] barrels to 218 million barrels. The other large projects that underpin our 11% compound annual production growth forecast through 2009 are all continuing to progress on schedule. We don't think the outlook for Devon has ever been better. We look forward to talking to you again on our next call. Take care.