德文能源 (DVN) 2008 Q3 法說會逐字稿

Welcome to Devon's third-quarter 2008 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.

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 perspective on the company, then Steve Hadden, our Executive Vice President of Exploration and Production, will cover the operating highlights. And wrapping 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'll remind you that we ask you to limit each call in to one question and one followup. We'll 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 web site.

During the call today, we will be tweaking some of our fourth-quarter estimates, and I want to remind you that you can find the -- a summary of our estimates on our web site. If 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 in 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 US securities law. And while we always strive to give you 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 web site at DevonEnergy.com.

I also want to remind you that as a result of our decision to sell all of our assets in Africa and terminate our operations there, the accounting rules require us to exclude oil and gas produced from the 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're also providing you an additional table that gives the details of the statement of operations, as well as the production volumes 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 closed 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 analysts choose to report to First Call numbers that exclude discontinued operations. And the mean estimate of those analysts that did exclude discontinued operations was $3.06 for the quarter, and that's right in line with our adjusted earnings from continuing operations of $3.06 per share.

With those items out of the way, I'll turn the call over to 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 the challenges presented by 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 climbed to $2.6 billion, which is a 49% increase over the third quarter of 2007. Our net Barnett shale production set yet another record, averaging more than 1.1 Bcf of gas equivalent per day in the third quarter. We completed the sale of our interest in Coke view in the third quarter which which brings our aggregate after-tax proceeds from all of our African divestitures to more than $2 billion. And during the third quarter, we continued to deleverage our balance sheet by using cash to redeem $983 million of the exchange of the Chevron exchange debentures, which in turn freed up 14.2 million shares Chevron stock.

In the wake of the recent credit deteriorations, I want to take a few minutes with you to comment on Devon's financial position. 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 long maintained the policy of doing business only with the highest grade credits and are spreading our exposure over all 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 own 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 coal bed methane natural gas field. This field encompasses 51,000 net acres and is located in east central Utah. We estimate the proved relatives associated with the assets are 210 billion cubic feet of gas. In addition to access of substantial unproven potential.

With the transaction, Devon also has 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 coal beds. 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've said many, many times in the past, it has always been our philosophy to deleverage during 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 properties but, in fact, to take advantage of them. And we've done that once again this time. Year to date, we have generated cash flow before balance sheet changes of $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 elected 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 at attractive prices and, indeed, exactly that has happened.

Since we announced our second-quarter results, we have acquired 50,000 net acres in the Haynesville Shale at an average cost of $3,500 per acre. In the Horn River up in Canada, we've acquired an additional 46,000 net acres at about $4,700 per acre. This activity has 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 plays. 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 built a position of almost 1.4 million net acres in four new, unconditional gas plays. This includes 153,000 acres in the Horn River, 580,000 acres in the Haynesville, and 650,000 acres in two new shale plays that we're not ready to identify or discuss.

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 derisk these plays with additional drilling and evaluation. Through this derisking, the additional acreage we have acquired and the transactions we plan 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 to the 2.4 trillion cubic feet we talked about in March. Assuming that we're successful in closing these transaction, our 2008 E&P capital expenditures will climb $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, gave us cash.

When you include the impact of the Chevron transaction and capitalized G&A and 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 are between 520 and 570 million barrels. When you do the math you will see that this gives us both a very attractive F&D 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 certainly will 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 transaction with Chevron would give us a net debt-to-cap ratio of less than 16%. Cash on hand of $600 million. And more than $2.5 billion of an available unused line of credit.

Clearly we're not sacrificing either our strong balance sheet or our strong liquidity to capture these compelling opportunities. Our financial positions remain strong. Following the successful conclusion of these transactions, we have in effect liquidated our position in Africa and redeployed those proceeds into high growth assets in North America. As a result, we are increasing our focus in areas where our technical expertise and established base of operations gives us the ability to effect -- to compete very effectively with anybody. With that I'll turn the call over to Steve Hadden.

Thanks, Larry, and good morning to everyone. I will begin with a quick recap of the companywide drilling activity.

In the third quarter, we drilled 636 wells. Of these, 22 were classified as exploratory with 91% successful. Remaining 614 wells were classified as development, of which 98% were successful, giving us an overall success rate for the quarter of roughly 97%. Our total rig count averaged 158 rigs during the third quarter with our operated rig count peaking in September at 106 rigs running. Capital expenditures for exploration and development were 2.1 billion for the quarter. Bringing the year-to-date e&p CapEx to $5.5 billion. Let's now move to the quarterly operational highlights beginning with the Barnett shale field in north Texas where we currently have 38 Devon-operated rigs operating. We continue to see excellent results from our horizontal in-field drilling programs. During the third quarter, we bought 67 wells on line that 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 Gasper day.

In addition, we're now seeing 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 on line with an average IP rate of 3.7 million cubic feet per day. These were two exceptional wells, and I'd caution that we don't think this will be typical. These two wells do, however, demonstrate 250-foot offsets have significant potential in some areas. In total during the third quarter, we bought 142 Barnett wells on line at an average rate of 2.3 million cubic feet of gas per day.

Our net Barnett Shale production set another record averaging more than 1.1 billion cubic feet of gas equivalent per day in the third quarter. This of 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 in Texas and northeast 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 would 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 interests hole 103-H located in Penola 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 7-H, located in Shelby County, Texas, is also drilling. We expect to have results from both these wells in our year-end call. Our focus in the Haynesville Shale throughout the remainder 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 plan 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 west 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 lime. We completed 3 outstanding 100% vertical wells in the Haynesville lime. The Oliver 4 IPed at 26 million feet a day, the Case 3 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 drill and complete, making them very economic. We initialed a three 3-D seismic shoot over the third quarter and plan to drill six additional wells in the fourth quarter, with our first horizontal well planned for the first quarter of 2009 in the line. It's early in the development of the Haynesville line, additional work needs to be done that it will be determined what the spacing will be. With more than 24,000 net acres in the Stockman field alone we believe we have a meaningful location and will keep you updated. Also in East Texas, in the Carthage area, we drilled 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 the third quarter.

Despite temporary shutins 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. Southwest of Carthage at Grossneck, we completed three outstanding Bossier sand wells in the Nansu Gale field in the third quarter. The Peyton 12-H IPed at 23 million a day. The Peyton 17-H at 17 million a day, and the And the Hill 15-H at 10 million a day. These wells helped drive our net Grossbeck production to a record 100 million cubic feet of gas per day, up 11% from the second quarter 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. Up 26% from the second-quarter average. Up 139% compared with the third quarter of 2007. We bought a total of 26 wells on line during the third quarter with an average IP rate of 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 per day. In early October, we bought our 200 million cubic feet a day North Ridge gas plant on line 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 101 million cubic feet of natural gas per day, net to Devon. In Washakee Basin in Wyoming, we had three rigs running during the quarter and drilled a total of 14 operated wells. We finished completion operations on our first horizontal well in the field during the third quarter, and we're currently evaluating those results. Our net Washakee production averaged 114 million cubic feet of gas equivalent per day in the third quarter, up 15% compared with the third quarter of 2007.

Now shifting to the Gulf of Mexico, I'll 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 were producing approximately 50,000 -- equivalent barrels per day in the Gulf of Mexico. We now have restored 33,000 barrels of oil equivalents per day and expect another 5,000 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 deep water program, but drilling programs are now back underway. On the exploration front the Damascus prospect on Walker Ridge 581 has reached 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 Canyon 596 is currently drilling below 21,000 feet, and will likely be on location through year end. Devon has a 50% interest in Bass.

At jack in St. Malo, we carried out successful appraisal operations in the third quarter. We also negotiated an acreage trade to increase our ownership in the St. Malo unit by 2.5%, giving Devon a 25% working interest in both jack and St. Malo. With the owners in these two large Tertiary projects continued to work toward 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, we began drilling the Cascade number three last week. This will be one of the initial producing wells at cascade. A design and construction of the production facilities is on schedule. The installation of the risers, FPSO Moorings, flow lines, and 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 at Caskeda in the third quarter. Devon will operate the well. We believe Caskeda is the largest of the four lower Tertiary discoveries that Devon has participated in to date. Finally, in the deep water Miocene, we drilled an appraisal side track of our 2006 mission deep discovery. The appraisal well locationed on Green Canyon 956 was drilled down dip from the initial discovery well and confirmed the initial discovery. The partners are evaluating the results to determine our next move. Also, in the deep water 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 and our Lloydminster oil play in Alberta, we are continuing a five rig program and drilled 137 new wells in the third quarter. Total net production from Lloydminster averaged 42,600 barrels a day in the quarter, up 8% over the third quarter of 2007. We commenced operations of a second 10,000 barrel-a-day expansion at our Manitoken plant in Lloydminster just a few days ago. The extension supports our growing production volumes in the area. Our 100% Devon-owned Jackfish thermal heavy oil project in eastern Alberta, we continue to see excellent performance from the plant and the reservoir. Production reached 18,000 barrels a day in the third quarter. We remain on track to achieve a sustainable rate of 35,000 barrels a day in the first half of 2009.

In early September, we received regulatory approval for our Jackfish two project. Light work has begun at Jackfish two, which is about four miles west of Jackfish. Once fully operational in 2012, Jackfish two will add another 35,000 barrels of day of oil production, doubling the size of our jackfish operations. Like Jackfish, Jackfish two represents an estimated 300 million barrels of recoverable oil net to Devon's 100% interest. Evaluation of a third potential jackfish project is underway with additional drilling slated for this winter to further define the reservoir. In the Horn River Basin in northern British Columbia, we added to our lease position during the third quarter and now hold approximately 153,000 net acres in the play. We plan to drill two horizontal wells in the fourth quarter as we continue to evaluate the emerging shale play.

Moving to the international arena in September, we announced the preliminary results of our pre-solid exploratory located in the Oahu prospect well in the Campos basin offshore Brazil. In October, the well on block BMC-30 was drilled on down to the total depth of about 20,000 feet. We're encouraged by the more than 150 feet of net pay found in the well and look forward to working with our partners to further assess this discovery. Based on the limited data that we have to date, we believe it's too early to quantify the resource potential or to clear commerciality. The next step in -- is a flow test that the partners are planning for next year, and Anadarko operates Oahu and Devon has a 25% working interest. In Azerbaijan, where Devon has a 5.6% interest in the ACG oil field, our share of ACG production averaged about 11,000 barrels a day in the third quarter compared to an expected 15,000 barrels a day. Planned transportation interruptions and shut-ins to a subsidy gas leak led to the shortfall. Transportation routes are fully operational, and the operators are working to restore production. But it's uncertain when the field will return to full production.

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

Thank you, Steve. Good morning. I plan to take you through a quick analysis of the key drivers that shaped our third-quarter financial results and will review how these factors impact our outlook for the fourth quarter. As a reminder, we've reclassified the assets, liabilities, and result of operations in Africa as 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.

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 in line 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 and the operational down time at the acg field in Azerbaijan that Steve mentioned, which, in aggregate, reduced third-quarter production by about two million barrels. Overall, Devon's companywide 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 two million barrels lost in the Gulf and ACG. And the US onshore segment delivered that -- that strong growth despite production curtailments resulting from Hurricane Ike. Led by growth from our Barnett shale and east Texas fields, US 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 sag-d and Lloydminster products 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 and 238 barrels. The primary drivers of this growth will again be our core US onshore properties and the continued ramp up of production from our Jackfish oil sands project that Steve described.

Moving on to 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 remain narrow with the result of price realization necessary all of our producing regions came in at the top end of our guidance range. Looking to the fourth quarter, as Jackfish and Pole volumes become a larger part of our volume 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 averaged $10.25 per MCF in the third quarter, a 66% increase over the third quarter of last year. Our company wide gas price r realizations before the impact of 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 and Canada. However, this was partially offset by weaker price realizations in the Rocky Mountains. In addition, in the third quarter, cash settlements on hedges reduced our realizations by $1.01 per MCF, giving us 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 differentials widening in most regions, we now expect fourth-quarter natural gas price realization before the benefit of these hedges to approximate 70% of NYMEX for the US on-shore, 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 business continue to deliver very impressive results despite challenges in natural gas processing due to Hurricane Ike. For the third quarter, marketing and midstream operating profit totaled $169 million, that's a 28% increase over our third-quarter 2007 results.

Once again, strong natural gas liquids pricing and 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 $120 million to $140 million, bringing the full-year marketing and midstream profit to between $660 million and $690 million.

The final item I'd like to cover before we move to expenses is the net gain on oil and gas derivative instruments. In the third quarter, we recorded a noncash unrealized gain of $1.8 billion from a mark-to-market accounting adjustment related to our natural gas and oil hedges. This fully offsets the noncash losses that we recognized in the first half of the year. In today's earnings release, we provided a table that identifies items generally excluded from analysts' estimates, and this unrealized noncash gain from our hedges is 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-quarter 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 costs due to post storm repairs and inspections. Looking to the fourth quarter, with additional production volumes coming back on line, we expect our unit LOE to decline to between $9.30 and $9.50 per barrel equivalent.

Third-quarter DD&A expense for oil and natural gas properties came in at $13.34 per barrel. And that result is right in line with the guidance range that we provided during our second-quarter conference call. For the fourth quarter, we expect a DD&A rate of $13.30 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 noncash expense due to the issuance of our annual equity compensation grants and including this noncash expense, we expect fourth-quarter G&A expenditures to increase to a range of $165 million to $175 million.

Now shifting to interest expense. Interest expense 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 that we've been discussing. For the fourth quarter, we anticipate interest expense to range between $65 million to $75 million.

Moving to income taxes, reported third-quarter income tax expense from continuing operations came in at $1.2 billion or 33% of pretax income. However, when you back out the impact of the noncash mark-to-market hedging adjustment, you get a current tax rate of 12% and a deferred rate of 18% for a total income tax rate of 30%. That's right in line -- right at the mid-point of our full-year guidance. Moving to the bottom line, earnings from continuing operations adjusted for items that analysts don't forecast came in at an impressive $1.4 billion or $3.06 per diluted share. This represents a 97% increase over 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 us 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. So at this point, I'd like to open it up for Q&A. Vince?

Operator, we're ready for the first question.

(OPERATOR INSTRUCTIONS). Your first question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed with your question.

Good morning. Just a question on your leasing both in the Haynesville and Horn River basin. Can you talk about the royalty that you're paying, using?

Yeah. This is Steve. I'll talk to you in the Haynesville, the 100,000 acres, the royalty runs about a quarter on average for the new the 100,000 that we're adding.

Okay.

We're adding that to that 483,000, where it probably averages closer to -- closer to 1/8.

Okay. And then Horn River?

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

Yeah, David, that was all crown acreage. So there's not a negotiated royalty oh that.

Okay. Perfect. And then looking at your financial position and the -- it was $1.4 billion of acquisitions in the quarter. Is that -- that was the right number? Just wanted to verify that. In fourth quarter?

I think that was 1.4 included, some of the acquisitions in the third quarter and the acquisition that's we planned to close in the fourth quarter.

Okay. So it included --

That includes both.

That's total second half of the year.

400 in the third quarter and the balance we think --

Okay.

And what we were really talking about, David, is -- is what we had done over and above our mid-year capital forecasts that we gave you at the end of last quarter.

Okay. That's helpful. And then looking at kind of operation results in each one of the areas, I mean delivering pretty high rate wells, when you think about a horizontal well in the line, in the Haynesville Line, how much better results do you expect than that?

That's a great question. Right now we're drilling vertical wells. And, 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're very up -- of course, with those results when you see those kind of wells with only $5.5 million of capital, they're extremely economic. They hold up relatively well. And -- and so we're very excited about the vertical wells that we're drilling. We will drill that first horizontal well in January and just see what we get. You know, the old ratio of 3 to 5, we're not sure if that 3-5 times the rate, we're not sure if that will hold in the lime.

Okay. And then on the marketing in midstream, just the detail on the fourth-quarter guidance. What are you building in for kind of an average NGL percent of NYMEX oil? Around the 40%, 45% we're seeing snow.

Yeah. It's running around 48% right now. And I think that's the numbers that we're running through the model for the fourth quarter.

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

Well, our best guess at this time is that it will probably go back to the 50% to 60%. But obviously with all the turmoil we're seeing in the credit markets and how that's affecting not only our industry but downstream consumers, that's certainly subject to some fluctuation.

All right. Thanks, guys.

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

Thank you. Good morning.

Good morning.

Going back to the Haynesville lime wells, how are you thinking about the up hole opportunities and, you know, if you think about co-mingling -- first of all, is that even possible or worthwhile? And how do you think about the total potential from the couple wells that you've drilled there?

Well, Brian, lets me see if I can -- I can break this down. We're focused in both -- obviously there's multiple pays there in that area. You've got everything from the Travis Peak down through the Pettitte, the Cotton Valley, the Haynesville Shale and the Haynesville Lime which sits below the shale. Right now we're focused on not co-mingling those and working on getting a good read on the long-term performance of the lime. And testing the lime across our acreage position and in a few other places. So we -- we don't have plans right now to do co-mingled 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 the Haynesville Shale and producing. And then these two horizontal wells will be down here very quickly. We'll frac the first one just next week and get those results. Then the second one drilling in Shelby won't, we'll have those results sometime -- county, we'll have those results sometime in the fourth quarter and continue with that horizontal program. So we're not thinking of it in terms of a co-mingled program at this point.

Okay. From a big picture perspective, how are you looking at 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 what we've seen this quarter in the last couple?

Brian, this is Vince. I'll take a shot at that. I think that the -- the key thing that you said is that we plan to live within our cash flow. And we're running a variety of scenarios right now for capital spend, for 2009, under various commodity price environments. And that's still a pretty big wild card. You know, we've provided some -- some guidance, 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've made a -- you know, we are very opportunity rich at this point. We've made some big strides, especially if we can close these deals that we're looking forward to closing in the fourth quarter. And I think that that is not an event that we would -- not a pace that we would expect to repeat every year. So we'll be focused more on developing what we have in 2009 than making large acreage captures like we did in the second half this year.

And Brian, if I can maybe just add a couple of point that Larry was talking about. This is John speaking, that Larry mentioned earlier, I think they're really important. What we've done here, first of all, and we've had some terrific opportunities to pick up very, very attractive acreage recently. And as Vince said, we have tended to be opportunity driven.

And what we really did is -- as Larry said, we swapped the -- in essence swapped the African properties for these very, very good properties in North America where we have the fiscal and regulatory stability that we have. But it's 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're not going to erode that.

Great. Thank you.

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

Thank you, gentlemen. A question concerning the Haynesville Lime. A question on what's controlling the productivity and how broad is it inside Stockman Field and outside?

Yeah. It's -- Tom, it's -- this is Steve. It's relatively early in the plays. This is the first preface I want to give to these comments. And, we've drilled these wells, and gotten very good results early on. Right now, in the area, we have 24,000 acres, net acres just in the area where we've been drilling these wells, and we're in the process of defining the limit of the field where we can get that kind of repeatable performance. But that being said, we think there's significant running room there. There's questions like at those rights, what's the appropriate spacing, you know, what are the limits within that -- within that -- within that area of the lime, that perspective area of the lime. And then, of course, we're expanding our thinking to other areas, looking to where the lime may be public sector. So it's -- it's relatively early, and, you know, we're -- we're not at a point to where we'll talk about what we think is driving the performance of the wells at this point because we think that's a -- a bit of a competitive issue right now.

I understand. Jumping over to Grossbeck in light of your continued success there, are you anticipating revising your 90 million-barrel resource potential upward at any point?

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

Great. Just -- one question on your acreage acquisition there in the Haynesville, where was that, the 50,000 acres?

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

And similar question for Horn River. Do you see that incremental acreage is being just as prospective as your original holding?

Absolutely. We think it's as good or better than the original acreage that we've assembled there. So, that last 46,000 acres we added with that sale fit right in, and -- and compete very well on -- as far as reservoir quality in the shale there. So we're real excited about that position. We're about 153,000 acres, which is one of the top holders in the -- in the play.

Thanks, guys.

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

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

We think there's upside. We aren't prepared at this point to really talk about -- about the upside. It's a great position for us. Number one because it has a -- we think it has a significant potential in the Farren, which is the primary coal seam that's being produced right now. And we have a lot of experience in that area. We're looking forward -- we just got the property, we're looking forward to working with the operator, which is Conoco. They have about 25%. And XTO is in it with 21. And we have 44%. We're just now really digging into that. We do think there's upside potential. But we're not at a point to where we talk about it in some detail yet.

Okay. Steve, secondly weather and traffic did you trade for that additional interest in the St. Mallow unit?

Essentially what it was was we had a position of -- a -- essentially what it was was we had a position of a small unit called Julia. I think about it in my mind, it's just to the east, maybe a little bit to the north and east of where St. Malo is, and we traded a -- a small interest in Julia for that 2.5% in St. Malo.

Okay. And -- and finally this relates to a certain extent to one of the questions that's been raised up to this point. It almost appears as 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 sweet spot or 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?

Well, Mark, I don't think that -- it was as Steve said, it wasn't 50,000 acres in -- in one area and the next 50,000 acres isn't in one area. What we did is we continued to increase our interests and fill in in and around the areas that we think are the most prospective in the area. And Steve and his folks have done a lot of work on doing some very detailed isopacked mapping of the thickest parts of the shale and where we think the most commercial and best parts of that play are going to be located. And so it's really -- it's really scattered around there but adjacent to areas where we already have interest so that we can take advantage of scale and -- when we really start our drilling operations.

You know, clearly the east Texas part of the play is going to be a very, very attractive area. But it's still way too early in the development of this field to say where the sweet spot or the sweet spots, there may be several in this field, are located.

Okay, guys. Thank you very much.

(OPERATOR INSTRUCTIONS). Your next question comes from the line of Rehan Rashid with FBR Capital Markets. Please proceed with your question.

Good morning. On the deep water side, US Gulf of Mexico, is there any thoughts on what the program could look like for '09?

Well, yeah, this is Steve. We'll continue with the appraisal work that we talked about on St. Malo and Jack. We'll -- we'll be drilling a well -- actually we'll spud the well at Caskeda, definitely in this fourth quarter. And then be drilling into -- in through the first quarter of next year on the Caskeda well. We also potentially could have another exploratory well -- operated exploratory well from the exploration standpoint, and we'll drill, you know, we'll 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 toward that first production in 2010. So, principally you're going to see us doing appraisal work and the development work at Cascade. And then we -- we may have the exploration well or two in the deep water, but we're just going through our 2009 budget now.

Got it. Steve, sticking with the deep water here, all the drilling that you guys have done, say, over the last year or two, anything that has changed or -- or what have you added to your knowledge base with regards to how the evolution would look like in the subsalt US versus maybe kind of what it seems like in the more faster evolution on the Brazilian side?

Well, in -- in the Gulf of Mexico, we're continuing to add to our knowledge base. You know, we've got a couple of very good discoveries on the go. And, what we're learning in 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're able to also go through that information and combine that information with what we're getting out of the -- the Cascade operation from the a completions standpoint and completion design standpoint, also from a facilities standpoint where we'll have the first FPSO in the Gulf of Mexico. So we're getting a lot of information and moving up the learning curve quite quickly in the Gulf of Mexico. And we'll bring that to bear along with our partners' experience when we look at places like Caskeda and potentially if we have a discovery at Bass, we'll apply it there. In the -- in Brazil, it's still a bit early.

But obviously we have a bit of experience in Brazil with FPSOs and that operation because we bought the FPSO in for Pulvo and have a good relationship with Petrobras and are partners with them on many of those on those blocks. We also obviously can bring to bear that experience to bear in the Gulf of Mexico working together with either Petrobras or other partners that we have in the -- in the -- in Brazil. And apply those learnings. Though I think we feel very good while weather we're positioned there from our learnings and development standpoint. And we're very encouraged by the Oahu discovery and by our inventory of drillable opportunities we have both in the pre-salt and in some other targets.

Okay. Thanks. On going to Haynesville lime quickly, anything that you can share in terms of veil design both for the vertical one that you just drilled, and how are you thinking about the horizontal frac numbers, length that you can share?

Well, not -- not much at this point. You know, where -- basically the Ip's and the performance of the wells, so we still view it as really competitive. And -- and an evolving opportunity that's -- that's really a -- a great opportunity at 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.

Okay. Okay. On the realized gas prices for onshore US, 70% of Nymex, any thoughts as to what we'll need -- will need to happen and where the boardwalk coming on line next year, how will that help and when should we -- can we expect this differential to improve a little bit?

Yeah. This is Darryl. You're right on. Of course, we just went through two months of exceptionally warm weather, being September and October and now going into -- into November. You couple that with the increased capacity -- the increased supply we've seen out of the Barnett shale, out of 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. Currently those differentials you probably have seen are in the 275 range. Boardwalk is due to come on. The first quarter. Right now our best estimate is February 1 or mid February.

Devon had substantial firm prosecution that pipeline. We expect that once that pipeline becomes operational that you will see those differentials which are now quite wide. We'll begin to narrow -- our hope is that they will go back to where they were maybe six, eight months ago. We do think that there is hope on the horizon obviously with the downturn in commodity prices and the financial situation we're 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 drilled as an industry over the last two or three years, we've seen about a 60% decline the first year with the base declining about 30%. So it's not going to take very long if we do have a downturn in active rigs drilling to see that impact on US supply.

On --

We're going to have to move on to the --

Thanks.

We can take one more question.

Okay. That's it for me, thanks.

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

Hi, good morning, everyone. I'm sorry if I missed a little bit more of this detail. But could you just walk me through the bigger picture driving force behind the Chevron transaction and the asset swap?

The big picture drivers on the Chevron transaction?

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

Well, 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 asset suite itself we think is a very reasonable value.

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

Okay. And then this kind of corners off of Brian's question earlier. Maybe asked a little bit of a different way. CapEx for 2009, a whole production flat. I know you haven't given too much detail on the full-year budget, but I'm just trying to get a feel for given the current environment where things shake out.

Well, I -- of course one way to approach that is our -- our &D has been running in the $16 to $18 a barrel range. Barrel equivalent range. And you can multiply that times our production number. And you -- you see where we are in term of maintenance capital versus growth capital.

Okay. Just want to make sure they tie it with my numbers. Okay. Thank you. I guess the last thing, moving up to the Horn River, there's been some pretty solid results coming from -- from some of 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 up there? And then secondly, is there any -- what do you see as the largest hurdles and/or constraints up there as you look at the development projects, maybe three to five years down the road?

Yeah. John, this is Steve. If you look at our acreage position in Horn River, we're adjacent to the major property holders that you 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're in a very good part of the play, and very good -- very good position relative to the shale. You know, some of the challenges up there simply exist around, the commercial challenges that end up being around, we're optimizing completions and making sure we get our costs down as it relates to the wells themselves. And get that in line relative to the good gas potential that we're seeing from the shale.

And then once you get above ground, of course, there are the commercial issues of both -- either processing or transporting the -- the gas, moving out. And we've 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 -- that we saw and still see to a degree in the Horn River area.

Right. Thank you very much. Okay.

Sometimes -- you 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 mother nature and more roads being all -- all-weather roads being put in, drilling pads, that type of thing. So the -- while the winter drilling aspect is more of a challenge, that will decrease over time.

Okay. Great. Thanks a lot, guys.

Operator, I'm showing a couple minutes after the top of the hour. We've -- minutes after the top of the hour. We've still got quite a few questions in the queue. Out of respect for everybody's time, we're going to cut the call off and remind you that we'll be around all day to answer any questions you want to follow up with. Thank you.

Ladies and gentlemen, thank you for your participation in today's conference. This participation in today's conference. This concludes the presentation. You may now disconnect. Good day.