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Executives

Vince White – SVP, IR

Larry Nichols – Chairman and CEO

Steve Hadden – EVP, Exploration & Production

John Richels – President

Darryl Smette – EVP, Marketing and Midstream

Analysts

David Heikkinen – Tudor Pickering Holt

Brian Singer – Goldman Sachs

Tom Gardner – Simmons & Company

Mark Gilman – Benchmark

Rehan Rashid – FBR Capital Markets

John Rogovin [ph] – Wachovia

Devon Energy Corporation (DVN) Q3 2008 Earnings Call Transcript November 5, 2008 11:00 AM ET

Operator

Welcome to Devon Energy’s third quarter 2008 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 Investor Relations. Sir, you may begin.

Vince White

Thank you and good morning everyone. Welcome to Devon’s third quarter 2008 conference call and webcast. Today’s call will follow our usual format after my introductory remarks Devon’s Chairman and CEO, Larry Nichols will provide his prospective on the company; then Steve Hadden, our Executive Vice President of Exploration and Production, will cover the operating highlights and ramping it up will be Devon’s President, John Richels, who will give us a brief financial review.

At that point we will open up the call to your questions and we will remind you that we ask you the limit each calling to one question and one follow-up. We will try to hold the call to about an hour and as a reminder, a replay of the call will be available later today through a link on our website.

During the call today, we will be taking some of our fourth quarter estimates and I want to remind you that, you can find the summary of our estimates on our website. You simply go to the Investor Relations section and click on the Estimates page. As far as guidance for 2009 goes, we typically give top-line production guidance and capital expenditure guidance for the upcoming year end December and then we follow that up with detailed guidance for production expenses and CapEx in an 8-K filing about the time we report earnings for the previous year.

Please note that all of our references today for plans, forecasts, expectations and estimates are forward-looking statements under U.S. Securities law, and while we always strive to give the very best guidance possible, there are many factors that could cause our actual results to differ from our estimates and we would encourage you to review the discussion of risk factors that can be found in the Form 8-K that we last filed in August.

One other compliance note, we will refer today to several non-GAAP performance measures, when we make reference to non-GAAP measures, we’re required to make certain disclosures under Securities law. You can find those disclosures on our website at devonenergy.com.

I will also want to remind you that there is a result of our decision to sell all our assets in Africa and terminate our operations there. The accounting rules require us to exclude oil and gas produced from our African assets from all reported periods and revenues and expenses for the discontinued operations are summarized in the discontinued operations line item. For your reference, we are also providing you an additional table that gives the details of the statement of operations as well as the production lines attributable to the divested properties.

On a reported basis, discontinued operations in the third quarter include a $97 million after-tax gain on the divested African properties, because we close the sale of our last producing property in September, discontinued operations will drop-off in future quarters.

As far as the street earnings forecast go, most analyst choose to report the first call numbers that exclude discontinue operations and the mean estimate of those analysts that did exclude discontinued operations was $3.06 for the quarter and that’s right inline with our adjusted earnings from continuing operations of $3.06 per share. With those items out of the way, I will turn the call over to Larry Nichols.

Larry Nichols

Thanks, Vince and good morning everyone. What a difference a quarter can make this has been amazing. But in spite of the extraordinary conditions in the capital markets and challenges present of our two hurricanes in the Gulf of Mexico. And the disruptions to production in the ACG field in Azerbaijan, Devon had a really very good third quarter.

Reported net earnings reached a record $2.6 billion and excluding the mark-to-market hedging gains, net earnings were a very solid $1.4 billion. Cash flow before balance sheet changes, climb to $2.6 billion which is a 49% increase over the third quarter of 2007. Our net Barnett Shale production set, we had another record, averaging more than 1.1 Bcf of gas equivalent per day in the third quarter.

We completed the sale our of interest in Cote d’Ivoire in the third quarter, which brings our aggregate after-tax proceeds from all of our African divestures to more than $2 billion. And during the third quarter, we continued to de-leverage our balance sheet, by using cash redeem $983 million of exchange or the Chevron exchangeable debentures, which in turn freed up 14.2 million shares of Chevron stock.

In the wake of the recent credit market deteriorations, I want to take a few minutes with you and comment on Devon’s financial position and on September 30, Devon had $1.2 billion of cash on hand and very low debt levels. In fact our net debt-to-cap was 13% at the end of the third quarter.

In addition, we have more than $3 billion of unused credit lines and only $177 million of debt maturities that mature between now and the second half of 2011. This financial strength has allowed us to maintain access to the commercial paper markets throughout this entire recent credit crisis. Another way we’re defending our strong financial position is by carefully managing our exposure to counterparty risk.

We had no exposure to Lehman and we have all maintain the policy of doing business only with the highest spread credits and then spreading our exposure overall of those firms. We have recently improved our cash position, as well as improved our attractive oil and gas property position with a transaction that we announced earlier this week with Chevron.

As I said earlier we owned 14.2 million Chevron shares, which were associated with the exchangeable debentures that we retired in August. We have now transferred those shares to Chevron in exchange for $280 million in cash from Chevron and Chevron’s 44% working interest in the Drunkard's Wash coalbed methane natural gas field.

This field encompasses 51,000 net acres and is located in east-central Utah. We estimate the proved reserves associated with the assets are 210 billion cubic feet of gas, in addition to access substantial unproven potential. With the transaction Devon also adds net production of about 40 million cubic feet a day to our interest.

This is a high quality asset and we look forward to working with our partners to leverage our over 20 years of success in dealing with coalbed and we want to realize the significant untapped potential that this field holds. There are no taxes that were payable with this transaction so it was very tax efficient transaction.

As we have said many, many times in the past it has always been our philosophy to do leverage during the times of strong commodity prices, so that we’re well positioned during price downturns. This has allowed Devon to not only manage through weak oil and gas proprieties, but in fact to take advantage of them, and we have done that once again this time.

Year-to-date we have generated cash flow before balance sheet changes to $7.9 billion. This has easily funded our capital expenditures and has provided free cash flow of $1.5 billion. This free cash flow coupled with $2.1 billion of net after tax proceeds from Africa and the $1.4 billion of cash we had on hand at the beginning of the year has allowed us to repay $3.6 billion of debt and preferred stock this year, and that includes the Chevron exchangeable.

In addition to repaying that debt, our intention at mid year was to continue the common stock repurchasing program that we began earlier this year. However, as the severity of this credit crisis became apparent, we believe that the value of liquidity was dramatically increasing. We therefore like to put our share buyback program on hold until we could see how this situation sorted itself out.

We also believe that the environment was unfolding that could result in an opportunity to acquire high quality assets to the attractive prices and indeed exactly that has happened. Since we announced our second quarter results; we have acquired 50,000 net acres in Haynesville Shale at an average cost of 3500 per acre. In Horn River in Canada, we’ve required an additional 46,000 net acres at about 4700 per acre. This activity as required about $400 million of additional capital over and above our mid-year forecast.

In addition we’re currently working on several acreage acquisitions that we hope to close by year end; that would bolster our position in core areas and some of our emerging place. If we’re successful in completing all of these transactions we will have added over 700,000 net undeveloped acres during the year. In total we will have build a position of almost 1.4 million net acres in four new unconditional gas price.

This includes 153,000 acres in the Horn River, 580,000 acres in Haynesville and 650,000 acres in two new Shale plays that we are not ready to identify or discus. When we provided the street with the resource update last March, we mentioned these plays and at that time we estimated that our net risk resource potential for these four plays totaled 2.4 trillion cubic feet equivalent. Since, then we’ve continued to de-risk these plays with additional drilling and evaluation.

Through this de-risking the additional acreage we have acquired and the transactions we planned to complete during the fourth quarter. We have increased our estimated net again risk resource potential more than tenfold in these four plays up to 26.5 trillion cubic feet, in comparison of the 2.4 trillion cubic feet that we talked about in March. Assuming that we’re successful in closing these transactions, our 2008 E&P capital expenditures will climb to 1.4 billion to approximately 8.7 billion.

This is before the impact of the Chevron transaction, which of course did not require a cash outlay in fact give us cash. We include the impact of the Chevron transaction and capitalized G&A in interest. We now expect total drill bit capital of $9.1 billion to $9.3 billion for 2008. The associated drill bit reserve additions that we now expect, were between 520 million and 570 million barrels.

When you do the math, you will see that this gives us both a very attractive F&D reached a cost and a very competitive F&D number and this is despite spending over $1.5 billion on undeveloped leases, leases that of course will not add any oil and gas reserves this year, but they are certainly well in future years. We find that a very attractive result.

Also even after these acreage acquisitions, Devon’s balance sheet remains quite strong. Our balance sheet pro forma these acquisitions and pro forma the transactions with Chevron, we give us a net debt-to-cap ratio less than 16%, cash on hand of $600 million and more than $2.5 billion of unavailable unused line of credit, but clearly we are not sacrificing either our strong balancing or our strong liquidity to capture these compelling opportunities. Our financial positions remained strong.

Following the successful conclusion of these transactions, we have an effect liquidate on our position in Africa and redeployed those proceeds in the high growth assets in North America. As a result, we are increasing our focus in areas, where our technical expertise in established base of operations gives us the ability to affect to compete very effectively with anybody. With that I will turn the call over to Steve Hadden.

Steve Hadden

Thanks, Larry and good morning to everyone. I will begin with a quick recap of the company-wide drilling activity. In the third quarter, we drilled 636 wells, of these 22 are classified as exploratory with 91% successful, remaining 614 wells reclassified as development of which 98% were successful giving us an overall success rate for the quarter or roughly 97%.

Our total rig count average to 158 rigs during the third quarter, with our operated rig count peaking in September at a 106 rigs running. Capital expenditures for exploration and development were $2.1 billion for the quarter, bringing the year-to-date ENP CapEx to $5.5 billion.

Let us now move to our quarterly operational highlights beginning with the Barnett Shale field in North Texas, where we currently have 38 Devon operated rigs running. We continued to see excellent results from our horizontal in filed drilling programs. During third quarter, we bought 67 wells online were drilled on 40 surface acre spacing or approximately 500 feet apart, those 67 wells have an average IP rate of 2.2 million cubic feet of gas per day.

In addition, we’re now seeing the early results from our pilot infill program. These wells are spaced 250 feet apart, which results in one well per 20 surface acres. During the quarter we bought two of these wells online with an average IP rate of 3.7 million cubic feet a day. These were two exceptional wells and I would caution that we don’t think this will be typical. Now, these two wells do however, demonstrates 250 foot offsets have significant potential in some areas.

In total during the third quarter we bought a 142 Barnett wells online at an average rate of $2.3 million cubic feet of gas per day. Our net Barnett Shale production set yet another record averaging more than 1.1 billion cubic feet of gas equivalent per day in the third quarter. This was up 4% from the second quarter and up 30% compared with the third quarter of 2007. We continue to target a year end net production from the Barnett at 1.2 billion cubic feet of gas equivalent per day.

Moving east in the Haynesville Shale and east Texas and northwest Louisiana as Larry mentioned we added 50,000 net acres in the third quarter and expect to add an additional 50,000 net acres in the fourth quarter. This will bring our total Haynesville shale position to 580,000 net acres. During the third quarter, we initiated drilling on our first two horizontal wells in the Haynesville Shale. These 100% working interest hole 103-H located in Panola County, Texas has reached total vertical depth and is now drilling the lateral section. We plan to begin completion operations next week.

Our second Haynesville Shale horizontal well the 100% owned McSwain 7H located in Shelby County, Texas is also at drilling. We expect to have these results from both these wells in our year end call. Our focus in the Haynesville Shale throughout the reminder of 2008 and 2009 will be to better characterize our acreage through additional drilling, coring and testing in order to define the areas of the play, where we believe we can achieve consistent, repeatable results just as we did in the Barnett Shale.

We planned to drill two additional horizontal wells in the Haynesville Shale during the fourth quarter with two dedicated rigs running. One of the great things about our acreage position in east Texas and Western Louisiana is the stack pay zones. An example of this is that our Stockman Field in the Carthage area. Not only does this field have Haynesville Shale potential, but it also has deeper potential in the Haynesville line.

During the quarter we completed three outstanding 100% Devon vertical wells in the Haynesville Lime. The Oliver-4IP to of 26 million cubic feet a day, the case three at 22 million a day and the Jenkins-1 at 10 million a day. These wells only cost about $5.5 million on average to drilling complete making them very economic. We initiated a 3D seismic shoot over the filed during the third quarter and plan to drill six additional wells in the fourth quarter with our first quarter horizontal well planned for the first quarter of 2009 in the Lime.

Its early in the development of Haynesville Lime in addition of work needs to be done including determining what the optimal spacing should be, but with more than 24,000 net acres in the Stockman Field alone, we believe we have a meaningful inventory of future locations and we will keep you updated.

Also in east Texas, in Carthage area we drill 31 new wells in the third quarter, as part of our seven rig vertical Cotton Valley drilling program. In addition, we recompleted eight Carthage area wells during third quarter. Despite some temporary shut-ins due to hurricanes, our total net Carthage production averaged 266 million cubic feet of gas equivalent per day in the third quarter up 2% over the last year.

Northwest of Carthage at Groesbeck, we completed three outstanding Bossier sand wells in the Nan-Su-Gail field in the third quarter. The Peyton 12H IP to 23 million a day, the Peyton 17H at 17 million a day, in a Hill 15H at 10 million a day. These wells have drive our net Groesbeck production to a record 100 million cubic feet of gas a day, up a 11% from the second and up 38% from the third quarter of 2007.

We also saw strong quarterly production growth in our Woodford Shale program in eastern Oklahoma. Net production averaged 48 million cubic feet of gas equivalent per day in the third quarter and up 26% from the second quarter average and up 139% compared with the third quarter of 2007. We bought a total 26 wells online during the third quarter with an average IP rate, 42 million cubic feet of gas per day. Of these 26 wells 13 were Devon operated wells that had average IPs of 5.6 million cubic feet a day. In early October, we bought our 200 million cubic feet a day north ridge gas plant online for processing Woodford production for Devon and other producers.

Moving to the Rockies; in the third quarter, we set an all-time production record at the Powder River Basin in Wyoming, we exited the third quarter producing a 101 million cubic feet of natural gas per day net to Devon. In Washakie Basin in Wyoming, we had three rigs running during the quarter and drilled total of 14 operated wells. We finish completion operations on our first quarter horizontal well in the field during the third quarter and we currently evaluating those results.

Our net loss key production averaged to 114 million cubic feet of gas equivalent per day in the third quarter, up 15% compared with the third quarter of 2007. Now shifting into the Gulf of Mexico; I will give you a brief update on the status of our recovery from the impact of the hurricanes in the third quarter. I’ll remind you that prior to the hurricanes, we are producing approximately 50,000 equivalent barrels per day in the Gulf of Mexico.

We now restored 33,000 barrels of oil equivalent per day and expect another 5000 barrels per day to be restored before year-end as repairs are made to production facilities and transportation systems. Additional volumes will be restored in 2009 as third-party facilities are repaired. The hurricanes also caused temporary delays with our Lower Tertiary deepwater program, but drilling operations are now back underway.

On the exploration front Damascus prospect on Walker Ridge 581 is rich TD and is currently under evaluation. This is operated by Chevron and Devon is participating with a 28.3% working interest. The Devon operated Bass Prospect located on Keathley Canyon 596 is currently drilling below 21,000 feet and will likely to be on location through year end. Devon has a 50% interest in Bass.

At Jack and St. Malo we carried out successful appraisal operations in the third quarter. We also negotiated in acreage trade to increase our ownership in the St. Malo unit by 2.5% giving Devon at 25% working interest in both Jack and St. Malo. The owners in these two larger shale projects continue to work towards the selection of a final development concept and expect to sanction the development potentially in late 2009 or early 2010.

At Cascade our 50/50 Lower Tertiary project the Petrobras, we began drilling the Cascade number three last week. This would be one of the initial producing wells at Cascade. The design and construction of the production facilities is on schedule. Installation of the risers FPSO marines, flow-lines and the gas export line are all planned for 2009. First production from Cascade is expected less than two years from now in mid 2010.

Also in the Lower Tertiary we expect to begin drilling another appraisal well Cascade in the fourth quarter. Devon will operate the well. We believe Cascade is the largest of the four Lower Tertiary discoveries that Devon has participated in to date. And finally in the deepwater Miocene we drilled an appraisal side track of our 2006 Mission Deep discovery.

The appraisal well located on Green Canyon 956 was drilled down dip from the initial discovery well and confirm the initial discovery. The partners are evaluating the result to determine our next move. Also in the deepwater Miocene the Sturgis North well located on Atwater Valley block 138 was unsuccessful and has been plugged and abandoned. Devon had a 25% working interest in Sturgis North.

Moving to Canada in our Lloydminster oil play in Alberta, we are continuing a five rig program and drilled a 137 new well in the third quarter. Total net production from Lloydminster averaged approximately 42,600 barrels a day in the quarter, up 8% over the third quarter of 2007. We commenced operations of our second 10,000 barrel a day expansion at our Manatokan plant at Lloydminster just a few days ago. The expansion supports our growing production volumes in the year-end.

Our 100%Denven-owned Jackfish thermal heavy oil project in Eastern Alberta, we continue to see excellent performance from a plant and the reservoir. Production reached 18,000 barrels a day in the third quarter. We remain on track to achieve a sustainable rate at 35,000 barrels a day in the first half of 2009.

In early September, we received regulatory approval for our Jackfish 2 projects, light work has began at Jackfish 2, which is about four miles west of Jackfish. Once fully operational in 2012 Jackfish 2 will have another 35,000 barrels a day of oil production doubling the size of our Jackfish operations. Like Jackfish, Jackfish 2 represented an estimated 300 million barrels of recoverable oil net to Devon’s 100% interest.

Evaluation of a third potential Jackfish project is underway, but additional drillings slated for this winter to future define the reservoir. In the Horn River Basin in Northern British Colombia we added to our lease position during the third quarter and now hold approximately 153,000 net acres in the play. We planned to two horizontal wells in the fourth quarter as we continue to evaluate this emerging Shale play.

Moving to the international arena. In September we announced preliminary results of our pre-salt exploratory well located in Wahoo prospect in Campos Basin offshore Brazil. In October the well on block BMC-30 was drill on down to a total depth of about 20,000 feet. We’re encouraged by more than 150 feet of net pay found in well to look forward to working with our partners to further assess to this superior discovery, based on the limited data that we have for date, we believe it’s way to early to quantify the resource potential or to clear commerciality.

The next step is a flow test that the partners are planning for next year and Anadarko operates Oahu and Devon have the 25% working interest and Azerbaijan, where Devon has a 5.6% interest in the ACG oil field our share of ACG production average about 11,000 barrels a day in the third quarter compared to an expected 15,000 barrels a day.

High point transportation interruptions and shut-ins due to subsea gas leak led to the shortfall. The transportation rates are now fully operational and the operators working to our store production, but it’s uncertain when it field will returns full production.

I’ll now turn the call over to John, for review of the financial results. John?

John Richels

Thank you, Steve and good morning. I planned to take you through a quick analysis of the key drivers that shaped our third quarter financial results and review how these factors impact our outlook for the fourth quarter. As a reminder we reclassified the assets liabilities and results of operations in Africa at discontinued operations for all accounting periods presented.

I will focus my comments as a result on our continuing operations excluding the impact of the African operations. Well. Let’s begin with production. Devon’s third quarter production totaled $58.6 million equivalent barrels or 637,000 barrels per day that’s pretty much inline with our revised forecast of 59 million barrels.

Production for the quarter would have been well above our revised forecast had it not been for disruptions from the storms in the Gulf of Mexico in the operational downtime at the ACG field in Azerbaijan that Steve mentioned, which in aggregate reduced third quarter production by about 2 million barrels. Overall, Devon’s company wide production increased by 19,000 equivalent barrels per day or 3% when compared to the third quarter of 2007.

Production growth from our core North American onshore assets more than offset the 2 million barrels lost in the Gulf and ACG. In the U.S. onshore segment delivered that strong growth despite production curtailments resulting from Hurricanes Ike, led by growth from our Barnett Shale and east Texas fields, U.S. onshore production grew by 54,000 barrels per day or 16% over the third quarter of 2007.

Our Canadian business also contributed production growth it was up about 4% over the year ago quarter. The continued ramp up of oil production from our Jackfish SAGD and Lloydminster projects drove this growth. Looking ahead to the fourth quarter Devon remains on track to deliver meaningful production growth depending upon the timing of repairs in the Gulf of Mexico and Azerbaijan, we expect fourth quarter production volumes to increase to a range of 62 million to 63 million BOE.

This represents a 6% to 8% increase in sequential quarterly production and puts our full year production at between 237 million and 238 million barrels. The primary drivers of this growth will again be our core U.S. onshore properties and the continued ramp up of production from our Jackfish Oil Sands Project that Steve described.

Moving onto price realization starting with oil, in the third quarter the WTI benchmark price averaged $118.52 that represents a 58% increase over the third quarter of 2007. In addition to strong benchmark prices regional differentials remained narrow with the result of price realizations in all of our producing regions came in at the top end of our guidance range.

Looking to the fourth quarter, as Jackfish (inaudible) volumes become a larger part of our production mix. We expect our oil differentials to widen some. With that widening we now expect fourth quarter realized prices in Canada to come in at approximately 60% of WTI and fourth quarter realizations for our international segment to approximate 85% of WTI.

On the natural gas side, the benchmark Henry Hub index average $10.25 per Mcf in the third quarter a 66% increase over the third quarter of last year. Our company-wide gas price realizations before the impact that hedges, came in at near the mid point of our guidance at approximately 86% of Henry Hub as a result, natural gas price realizations remained strong in the Gulf of Mexico in Canada, however, this was partially offset by weaker price realizations in Rocky Mountains.

In addition in the third quarter, the cash settlements on hedges reduced our realizations by $1.01 per Mcf giving as a realized price including the hedging impact of $7.81 per Mcf. For the fourth quarter, we have approximately 60% of our natural gas production hedge with a weighted average floor of $7.77 per MMBtu. With differential widening in most regions, we now expect fourth quarter natural gas price realization before the benefit of these hedges, go approximate 70% of NYMEX for the U.S. onshore, 105% of NYMEX for the Gulf and 85% of NYMEX in Canada.

Turning now to our marketing and midstream business, Devon’s marketing and midstream operations continued to deliver a very impressive result despite challenges in natural gas processing due to hurricane Ike. For the third quarter, marketing and midstream operating profit totaled $169 million that is a 28% increase over our third quarter 2007 results. Once again, strong natural gas liquids pricing in increased throughput drove the increase in operating profit.

Looking forward to the fourth quarter, we expect declines in commodity prices to reduce our marketing and midstream operating profit to a range of about $120 million to $140 million, bringing the full-year marketing and midstream profit to between $660 million and $690 million.

Finally, I may like to cover before we move to expenses as the net gain on oil and gas derivative instruments. In the third quarter, we recorded on non-cash unrealized gain of $1.8 billion from a mark-to-market accounting adjusting related to our natural gas and oil hedges. This fully offsets the non-cash losses that we recognized in the first half of the year.

In today’s earnings release, we have provided a table that identifies items generally excluded from the analysts estimates in this unrealized non-cash gain from our hedges in that table.

Moving to expenses, our third quarter lease operating expenses totaled $591 million. This translates to $10.09 per equivalent barrel or about 10% higher than the second LOE per barrel. This increase resulted primarily from the impact of hurricane Ike not only did the storm reduce production volumes, but it also increased operating cost due to post storm repairs and inspections.

Looking to the fourth quarter with additional production volumes coming back online, we expect our unit LOE to decline to between $9.30 and $9.50 per barrel equivalent. Third quarter DD&A expenses for oil and natural gas properties came in at $30.34 per barrel, in that result is right inline with the guidance range, so we provided during our second quarter conference call. For the fourth quarter, we expect DD&A rate $30.30 to $13.50 per equivalent barrel.

G&A expense for the third quarter was $146 million; this is approximately $4 million below the low-end of our guidance range and $34 million less than the second quarter of 2008. This positive variance is primarily due to lower personnel expenses. The fourth quarter will include approximately $43 million of non-cash expense due to the issuance of our annual equity compensation grants and including this non-cash expense, we expect fourth quarter G&A expenditures to increase to a range of $165 to $175 million.

Now shifting to interest expenses; interest expenses for the third quarter totaled $69 million, when compared to the third quarter of last year reported interest expense decreased by $39 million or 36%. This decline in interest expense is due to the lower debt levels, so we have been discussing. For the fourth quarter, we anticipate interest expense to range between $65 million to $70 million.

Moving to income taxes; reported third quarter income tax expenses from continuing operations came in at $1.2 billion or 33% of pretax income. However, when you backup the impact of the non-cash mark-to-market hedging adjustment, you get a current tax rate of 12% and deferred rate of 18% for total income rate of 30% and that’s right inline rate at the midpoint of our full-year guidance.

Moving to the bottom line; earnings from continuing operations; adjusted for items that analysts don’t forecast came in an impressive $1.4 billion or $3.06 per diluted share. This represents a 97% increase over the third quarter 2007 adjusted earnings. Year-to-date we have generated cash flow before balance sheet changes of $7.9 billion comfortably funding $6.4 billion of capital investments and leaving us with significant cash flow

In summary our approach to the business has prepared as well for these turbulent times. We entered the fourth quarter with low-debt levels, $1.2 billion in cash and an asset base that will remain profitable during periods of lower commodity prices. Looking forward to 2009, we will continue to invest in our strong asset base, live within our cash flow and prepare to reap the benefits when oil and natural gas prices inevitably rebound.

With this point I would like to open it up for Q&A. Vince.

Vince White

Operator, we are ready for the first question.

Question-and-Answer Session

Operator

(Operator instructions) your first question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed with your question.

David Heikkinen – Tudor Pickering Holt

Good morning just a question on your leasing both in the Haynesville and Horn River Basin. Can you talk about the royalty that you are paying or using?

Steve Hadden

Yes, this is Steve. I will talk to you about in the Haynesville, with the 100,000 acres the royalty runs about a quarter on averages for the 100,000 that we are adding.

David Heikkinen – Tudor Pickering Holt

Okay.

Steve Hadden

We are adding net to that 483,000 were probably average is closer to 2/8.

David Heikkinen – Tudor Pickering Holt

Okay, and then Horn River?

Steve Hadden

Horn River has a sliding scale based on the Canadian royalty which is based on both the price and the well.

John Richels

Yes, David that was all crown acreage.

David Heikkinen – Tudor Pickering Holt

Okay.

John Richels

So, there is nothing not a negotiated royalty on that.

David Heikkinen – Tudor Pickering Holt

Perfect, and then looking at your financial position and that it was $1.4 billion of acquisitions in the quarter, is that was a great number just wanted to clarify that in fourth quarter?

John Richels

I think that was $1.4 billion included some of the acquisitions in the third quarter and the acquisitions that we plan to close in the fourth quarter

David Heikkinen – Tudor Pickering Holt

Okay, so that included.

Steve Hadden

That includes both.

David Heikkinen – Tudor Pickering Holt

That’s the total second half of the year.

John Richels

400 in the third quarter and the balance we think.

Steve Hadden

And what we really talking about David is what we had done over and above our mid year capital forecast that we gave out in the last quarter.

David Heikkinen – Tudor Pickering Holt

Okay, helpful. And then looking at kind of operation results at each one of the areas, I mean delivering pretty high rate wells. When you think about a horizontal well in the Haynesville Lime, how much better results would you expect from that?

Darryl Smette

That’s a great question David. Right now we are drilling vertical wells in, we would expect to see improvement with the horizontal wells, but we just haven’t drilled one yet and don’t have any benchmark to set on the Lime. So, we’re really taking a wait and see. We are very up of course with those results when you see those kinds of wells with only $5.5 million of capital.

They are extremely economic, they hold up relatively well and so we are very excited about the vertical wells that we are drilling. We will drill that first horizontal well in January and just see what we get. They are – the old ratio of three to five, we’re not sure if that three to five times the rate, we’re not sure if that will hold in the Lime.

David Heikkinen – Tudor Pickering Holt

Okay and then on the marketing and midstream just the detail on fourth quarter guidance. What do you building in for kind of an average NGL percent of NYMEX oils at around the 40% to 45% we are seeing now or?

John Richels

Yes, it’s running around 48% right now and I think that’s the numbers that were running through model for the fourth quarter

David Heikkinen – Tudor Pickering Holt

And then as you look forward to next year, do you think you normalize back to the 50% to 55%?

John Richels

Well, our best guess at this time is that we’ll probably go back to the 50% to 60%.

David Heikkinen – Tudor Pickering Holt

Okay.

John Richels

But obviously with all of the turmoil we’re seeing in the credit markets and how that’s affecting not only our industry, but a downstream consumer that’s certainly subject to some fluctuation.

David Heikkinen – Tudor Pickering Holt

Thanks guys.

Operator

Your next question comes from line of Brian Singer with Goldman Sachs. Please proceed with your question.

Brian Singer – Goldman Sachs

Thank you, good morning.

Larry Nichols

Good morning.

Brian Singer – Goldman Sachs

Going back to the Haynesville Lime wells. How are you thinking about that whole opportunities and ultimately if you think about commingling – first of all is that even possible or worthwhile? And how do you think about the total potential from the couple wells that you drill there?

Steve Hadden

Brian, let me see if I can break this down. We’re focused in both obviously there is multiple pace there in that area. You get everything from the Travis Peak down through the Pettit, the Cotton Valley, the Haynesville Shale and then the Haynesville Lime, which is just below the Shale. Right now, we’re focused on not comingling those and working on getting a good read on the long-term performance of the Lime and testing Lime across our acreage position and then in few other places.

So, we don’t have plans right now to do commingled completions in the Lime and the Haynesville Shale. We are continuing with our Haynesville work. We have probably a half a dozen vertical wells that are down in the Haynesville and producing – in Haynesville Shale and producing and then these two horizontal wells will be done here very quickly.

We will frac the first one just next week and get those results and then the second one drilling Shelby County. We’ll have those results sometime in the fourth quarter and then continue with that horizontal program so, we are not taking it up in terms of coming up program at this point.

Brian Singer – Goldman Sachs

Okay and from a big picture perspective, how you are looking at the production growth in 2009 overall in the context of trying to spend within your cash flow and how should we think about the aggressiveness of further leasing next year relative to you what we have seen this quarter in the last couple…

Vince White

Brian, this is Vince. I will take a shot at that. I think that the key thing that you have said is that, we planned a little within our cash flow and we are running a variety of scenarios right now for capital spend for 2009 under various commodity price environments and that is still a pretty big wildcard. We have provided some guidance over six or nine months ago, we showed you some expected growth curves under a couple of different practicing scenarios that kind of shows the variability with commodity prices, when you live within cash flow.

As far as the aggressiveness of leasing in 2009, I think we are a very opportunity rates at this point, we have made some big strives as especially, if we can close these deals that they are looking for the closing in the fourth quarter and I think that is not a pace that we would expect to repeat every year. So, we will be focused more on developing what we have in 2009 than making large acreage captures like we did in the second half of this year.

Steve Hadden

And Brain, if I can maybe just add a couple of points that Larry who was talking about as John speaking on that Larry mentioned earlier, I think they are really important. What we have done here, first of all and we have had some terrific opportunities to pick-up very, very attractive acreage recently and as Vince said, we tended to be opportunity driven and what we really did is as Larry said, in essence swapped the African properties for these very, very good properties in North America, where we have a physical and regulatory stability that we have, but it is really important for us to maintain the strong balance sheet and the liquidity, particularly in these times of uncertainty having that financial strength is a real key for us and we are not going to roll that.

Brian Singer – Goldman Sachs

Great. Thank you.

Operator

Your next question comes from line of Tom Gardner with Simmons & Company. Please proceed with your question.

Tom Gardner – Simmons & Company

Thank you. Good morning, gentlemen. A question concerning the Haynesville Lime just your thoughts on what’s controlling the productivity and just how broaden opportunity is it in side stock and field in outside?

Stephen Hadden

Tom, this is Steve. It is relatively early in the place. This is the first preface that I want give to these comments and we have drilled these wells and gotten very good results early on. Right now in the area we have 24000 acres, net acres just in the area where we have been drilling these wells, and we are in the process of defining those limits, but, we – the limits of the field where we can get that kind of repeatable performance.

But that being said we think there is significant running room there. There is questions like at those rates what’s the appropriate spacing, what are the limits within that area of the Lime that that perspective area of the Lime and then of course we are expanding our thinking to other areas looking to where the Lime maybe productive. So it’s relatively early and we are not at a point to where we will talk about, what we think is driving the performance of the wells at this point, because we think that’s a bit of competitive issue right now.

Tom Gardner – Simmons & Company

Yes, I understand. Jumping over the gross pack in light of your continued success there, are you anticipating revising your $90 million barrel resource potential upward at any point?

Steve Hadden

We’ll look at that again here coming at the end of this year and then very early next year and we will revise our resource potential there. We think to look at it generally on an annual basis unless we have a very significant event and I don’t see it’s making us a near term revision based on the results of those three wells at this point, but we will take another look at it in January and then make another assessment.

Tom Gardner – Simmons & Company

Great and just one question on your acreage acquisition there in the Haynesville, where was that the 50,000 acres?

Steve Hadden

It was really all over in between east Texas and some in Louisiana.

Tom Gardner – Simmons & Company

And similar question for Horn River, do you see that incremental acreage is being just as perspective issue original holding?

Steve Hadden

Yes, absolutely, we think it’s good or better than the original acres that we have assemble there so. That the last 46,000 acres we added with that sale, fit right in, and compete very well on as far as reservoir quality in the shale there. So, we are real excited about that position. We are about 153000 acres, which is one of the top holders in the play.

Tom Gardner – Simmons & Company

Thanks guys.

Operator

Your next question comes from the line of Mark Gilman with Benchmark. Please proceed with your question.

Mark Gilman – Benchmark

Hi, guys good morning. I guess a couple of things. First, Steve can you comment on the upside potential you see on the Drunkard's Wash acquisition?

Steve Hadden

We think there is upside. We aren’t prepared at this point to really talk about the upside, it’s a great position for us. Number one, because we think it has significant potential in Farren, which is primary coal seam that’s being produced right now and we have a lot of experience in that area. We are looking forward, we just got property; we are looking forward to work, which is Conoco. They have about 25% and then XTO’s was about 31 and we are sitting here with 44%. So, we are just now really digging into that. We do think there is upside potential, but we are not at the point where we talk about it in some detail yet.

Mark Gilman – Benchmark

Okay. Steve, secondly what you trade for that additional interest in the St. Mallow unit

Steve Hadden

Essentially what it was, we had a very small position in a discovery call Julia, which was I think its just, if I think about in mind it just to the east maybe a little bit to the north and east of St. Mallow – and we traded a small interest in Julia for that 2.5% in St. Mallow.

Mark Gilman – Benchmark

Okay and finally, this relates to certain extent to one of the questions that have been raised up to this point. It almost appears, if the lion’s share of the incremental acreage, maybe even the entire acreage package in the Haynesville, is located considerably west of where one might on a very preliminary basis be thinking in terms of a suite spot of the play. Is that an accurate observation in terms of how the acreage position as it stands currently plays out or would you choose to characterize it differently?

John Richels

Mark, I don’t think that it was as Steve said, it wasn’t 50,000 acres in one area and the next 50,000 acres is in one area, what we did as we continue to increase our interest in fill in and around the areas that we think of most perspective in the area and Steve then his folks have done a lot of work on doing some very detailed isopack mapping of the thickest parts of the Shale and where we think the most commercial in best parts to that play are going to be located and so, its really scattered around there, but adjacent to area where we all ready have interest, so that we can take advantage of scale and when we really start our drilling operations.

Larry Nichols

Clearly the East Taxes part of the play is going to be a very, very attractive area, but it still way too early in the development of this field to say where are the suite spot or the suite spots there maybe several in this filed are located.

John Richels

Okay guys thanks very much.

Operator

(Operator instructions)

Vince White

It appears that a couple of the questions in the queue were ended inadvertently dropped. So, if you got a question please renter.

Operator

(Operator instructions) your next question comes from the line of Rehan Rashid with FBR Capital Markets. Please proceed with your question.

Rehan Rashid – FBR Capital Markets

Good morning. On the deepwater side U.S. Gulf of Mexico is there any thoughts on what the program could look like for ’09?

Steve Hadden

Well, yes this is Steve. We will continue with the appraisal work that we talked about on St. Malo and Jack. We will be drilling a well; actually we will spud the well at Cascade probably in, well definitely in this fourth quarter and then be drilling in through the first quarter of next year on the Cascade well. We also potentially could have another operated exploratory well from the exploration standpoint and we will drill, we will finish drilling the first operated well, the first producing well at Cascade in the first half of the year and then drill the second well during 2009 for Cascade heading towards that first production in 2010.

So, principally you are going to see us doing appraisal work and the development work at Cascade and then we may have a exploration well or through in the deepwater but we are just going through our 2009 budget now.

Rehan Rashid – FBR Capital Markets

Got it, Steve just taking with the deepwater here have all the drilling that you guys have done let’s just say over the last year or two anything that has changed or what have you added to your knowledge base with regards to how the evolution would look like in the sub-salt you ask versus maybe kind of look what it seems like the more faster evolution on the Brazilian side?

Steve Hadden

Well in the Gulf of Mexico, we are continuing to add to our knowledge base, we have got a couple of very good discoveries on the go and what we are learning and working through issues around completions and production facility configuration and optimizing those things is very important that we get from Jack and St. Malo, but we are able to also go through that information and combine that information with what we are getting out of the Cascade operation from a completions standpoint and completions design standpoint also from a facility standpoint where we are going to have the first FPSO in the Gulf of Mexico and so we are getting a lot of information and moving up the learning curve quite quickly in the Gulf of Mexico and we will bring that to bare along with our partners experience when we look places like Cascade and potentially if we have a discovered at Bass, we will apply there.

In Brazil, it is still a bit early, but obviously we have a bit of experience in Brazil with FPSOs in net operation, because we bought the FPSO in for Polvo and we have got a good relationship with Petra brass and our partners with them on many of those blocks. We also obviously can bring that, bear that experience that we have in the Gulf of Mexico working together with either Petra brass or other partners that we have in the Gulf – in Brazil and apply those learning. So, I think we feel very good where we are positioned there from our learning’s and development standpoint and we are very encouraged by the Oahu discovery and by our inventory of billable opportunities we have both in the pre-salts and in some other targets.

Rehan Rashid – FBR Capital Markets

Okay, thanks. On going to Haynesville Lime quickly, anything that you can share in terms of well designed on both of the vertical one that you just drilled and how are you thinking about the horizontal frac numbers, length of well bore whatever that can share?

Steve Hadden

Well, not much at this point, where – and basically the IPs and the performance of the wells and so we still view this really competitive in evolving opportunity that is really a great opportunity of those kind of rates and that kind of economic leverage that we get in wells that are over 20 million a day for $5.5 million.

Rehan Rashid – FBR Capital Markets

Okay and on the realize on gas prices for onshore U.S. and 70% of NYMEX and any process to what will need to happen and where the boardwalk coming online next year, how will that help and when should be – what can we expect this differentials improve a little bit?

Darryl Smette

Yes, this is Darryl. You are here right on and of course, we have just went through two months of exceptionally warm weather being September and October and now going into November and you couple that with the increased capacity – or the increased supply we are seeing out of the Barnett Shale or the Fayetteville shale, out of east Texas, all of that gas is really trying to go to a constrained pipeline system going east and that has really affected differentials in those different areas and currently those differentials you probably have seen are in the 275 range.

Boardwalk is due to come on in the first quarter right now our best estimate is probably going to be February 1 and mid-February Devon has substantial front transportation in that pipeline, we would expect that once that pipeline becomes operational that you will see those differentials which are now quite wide. We will begin to narrow and our hope is that they will go back to where they were maybe six, eight months ago.

So, we do think there is hope on horizon obviously with the downturn in commodity prices in the financial situation we are in, we don’t know what the impact is going to be on drilling for this industry, but as you probably know for new wells we’ve drilled as an industry over the last two or three years. We have seen about a 60% decline in the first year with base that declining about 30%. So it’s not going to take very long if we do have a downturn and active rigs drilling to see that impact on U.S. supply.

John Richels

Rehan, we’re going to have to move on, we can take one more question.

Rehan Rashid – FBR Capital Markets

Okay. That’s it from me. Thanks.

Operator

Your next question comes from the line of John Rogovin [ph] with Wachovia. Please proceed with your question.

John Rogovin – Wachovia

Hi, good morning everybody. I’m sorry if I missed a little bit more this detail, but could you just walk me through the bigger picture driving force behind with Chevron transaction and the assets swap?

Steve Hadden

The big picture drivers on the Chevron transaction.

John Rogovin – Wachovia

Yes, if you look at the implied value on the asset, it just seems a little bit rich from a share assets value perspective. So I wanted to see if there was an underlying driving force that was not necessarily outlined in the press release?

Vince White

We, it’s important to bear in mind that had we just issued those shares to the exchangeable holders or sold the shares that we would have had a tax bill of approximately $350 million. So that impacted our assessment of the relative values of the transaction, but the value that we put on the Drunkard's Wash assets suite itself. We think it’s a very reasonable value.

Steve Hadden

Yes, there are two things you need to look at and looking at that. One is our alternative for – is what Vince just said our alternative to deal with that was to sell the shares and realize a very large tax gain up-front. Second is as we have said several times we think that field has significant undeveloped potential that given our expertise in this time reservoir we think we can add.

John Rogovin – Wachovia

Okay and then just kind of corners off the Brian’s question earlier maybe asked a little bit of a different way. Do you have an estimate of what you back of the enveloped maintenance CapEx number for 2009 just a whole production flat? I know you haven’t given too much detail on the full year budget, but just trying to get a feel for given the current environment where things shake out?

Larry Nichols

Of course, one way to approach that is our F&D has been running in $16 to $18 barrel range – barrel equivalent range and you can multiple that times our production number and you see where we are in terms of maintenance capital versus growth capital.

John Rogovin – Wachovia

Okay, I just want to make sure they tie with my numbers. Okay, thank you. I guess the last thing moving up to the Horn River. There has been some pretty solid results coming from some your competitors. Can you just give me an idea of where your acreage position is in relation to some of the larger caps that have had announcements out there? And then secondly is there any what do you see as a largest hurdles and/or constraints out there if you look at the development project maybe three or five years down the road?

Steve Hadden

Yes, John this is Steve. If you look at our acreage position in Horn River we are adjacent to the major property holders that you will see. The first partial that we captured up there was a little bit to the eastern side. This latest partial is just a little bit on the western flank, but still adjacent to the some of the other major property holders up there and then the other part of the acreage is right in between those two. So, we feel like we are in a very good part of the play in very good position relative to the shale.

Some of the challenges up there simply exist around, the commercial challenges that end up being around, we are optimizing completions and making sure we get our cost down as it relates to the wells themselves and get that inline relative to the good gas potential that we are seeing from the shale and then once you get above ground of course there are commercial issues of both either processing or transporting the gas moving out and we have worked with people in that area have dealt with those early challenges quite well we think and feel optimistic about the future and development going forward, but those were some of the challenges, that we saw and still see to a degree Horn River area.

John Richels

Sometimes, we will hear people talking as well about the fact that it’s a winter drilling area and that’s a challenge today, but as we move forward there are more and more roads being all weather roads being put in drilling pads that type of things. So, the while the winter drilling aspect is more of a challenge that will decrease overtime.

John Rogovin – Wachovia

Great, thanks a lot guys.

Vince White.

Operator I am showing a couple of minutes after the top of the hour. We still got quite a few questions in the queue. So, out of respect for everybody’s time we are going to cut the call off and remind you that we will be around all day to answer any questions you want to follow up with. Thank you.

Operator

Ladies and gentleman, thank for your participation in today’s conference. This concludes the presentation. You may now disconnect, good day.

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Source: Devon Energy Corporation Q3 2008 Earnings Call Transcript
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