德文能源 (DVN) 2007 Q1 法說會逐字稿

Welcome to Devon Energy's first quarter 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. (OPERATOR INSTRUCTIONS) This conference is being recorded. If you have any objections, you may disconnect at this time.

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

Thank you, and good morning to everyone.

Welcome to the Devon's first quarter 2007 conference call and webcast. I've got a few remarks to make and then following my introductory comments our Chairman and CEO, Larry Nichols, will review the highlights of the quarter and will update you on the progress of our divestitures. Following Larry's remarks, Steve Hadden who is our Senior Vice President, Exploration and Production, will discuss the operating highlights, and then our President, John Richels, will finish up with a financial review.

You will have a chance to ask questions following John's remarks, and as usual we will hold the call to about an hour. However, we will be available by phone throughout the rest of the day, so if we don't get to your question in the call, give us a call at the office.

A replay of this call will be available later today through a link on devonenergy.com. We will also be posting to our website a new issue of Devon Direct. Today's issue of Devon Direct is an electronic report that includes highlights from this webcast and provides links to some additional supplementary information.

Also, please note that all references today in our call to plans, forecasts and estimates are forward-looking statements under U.S. Securities Law. And as I have said before, we always attempt to provide you the very best estimate possible, but there are many factors that could cause our actual results to differ from the estimates that we provide.

In this context we encourage you to review the discussion of risk factors and uncertainties that is provided with our form 8(K) along with the forecast. One other compliance item, we will make reference today to some non-GAAP performance measures. When we use these measures, we are required to provide certain related disclosures. We encourage you to review those disclosures which are available on the Devon website.

Finally, I want to point out that as a result of our decision to sell our assets in Africa and terminate the -- our operations there, accounting rules require us to exclude oil and gas produced from the divestiture assets from our reported production volumes for all periods presented. The related revenues and expenses for the discontinued operations are collapsed into a single line item at the end of the statement of operations.

However, we have provided in today's release an additional table that gives you a detailed statement of operations as well as the production volumes attributable to the properties that we are divesting. You will note that the reported after-tax earnings from discontinued operations was 77 million in the first quarter. However, I want to point out that that doesn't mean that the discontinued operations would have actually had reported earnings of 77 million had we not decided to sell them.

The discrepancy occurs because accounting rules require us to stop recording depletion on the sale properties once they are designated for divestiture. In other words, had we not decided to sell these properties, we would have had net income associated with the divestiture properties of 56 million, that's 21 million less than the 77 million of income we reported from discontinued operations.

And that's really all related to 21 million more of expenses that we would have had had we not decided to sell them on an after-tax basis. The accounting treatment of the divestiture properties also muddies the water for the first quarter comparison to consensus estimates.

We polled the analysts that report estimates to first call and determined that half the estimates provided by the sell-side included the African operations and about half the estimates excluded the impact of the African operations. The mean estimate for the analysts that we contacted that included discontinued operations was $1.32 per share. That compares to our reported earnings per share of $1.44 diluted for the first quarter.

The mean estimate for the analysts that we were able to reach that excluded discontinued operations was $1.19 per share. And that compares to our actual earnings from continuing operations of $1.27 per share. So my point here really is that whether you compare our actual results to the estimates with or without discontinued operations, on an apples-to-apples basis our first quarter results were much better than the corresponding estimates.

With those items out of the way, I will now turn the call over to Larry Nichols.

Thanks, Vince, and good morning, everyone.

Devon's first quarter results were very strong, reflecting very good overall performance. As Vince has described, the first quarter net earnings and earnings per share came in better than expected. Cash flow before balance sheet changes was 1.5 billion. Most importantly, first quarter production of 52.9 million barrels equivalent from continuing operations was at the high-end of our forecasted range and represented 12% growth over the first quarter of '06.

And it is also Devon's fourth consecutive quarter of production growth from continuing operations. Importantly, we remained very solid and on track to deliver our full year 2007 production forecast of somewhere between 219 and 221 million Boe. That will represent a 10% growth over 2006, it's what we've been forecasting for some time. We do expect the second quarter production from continuing operations to be slightly higher than the first quarter at around 53 million Boe.

However, in the second half of the year as we realize our first production from Polvo, from Merganser and from Jackfish combined with the continued growth of our US onshore in places like the Barnett Shale, we expect production to grow throughout the third and fourth quarters, which will deliver us our 10% growth for the year. Steve Hadden will provide you updates on these growth drivers and other news here in a minute.

Before I wrap up my comments, I wanted to update you on our divestiture program. During the first quarter of this year, we took steps to divest our assets in Egypt and in West Africa. In April we announced that we had agreed to sell our Egyptian operations for $375 million.

When you exclude the $67 million of working capital associated with the Egyptian properties this works out to be about $38.50 per barrel of proved reserves or about $64,000 per a flowing barrel. We believe this very attractive evaluation is an indicator of the strength of the market for international and gas properties.

This is particularly true in our view of asset packages with both established production and additional growth potential. As with Egypt, the properties that we are offering for sale in West Africa include established production, operator ship in some properties, numerous development and exploitation opportunities and promising exploration upside.

As we close these transactions in the second half of the year, we expect to have a significant amount of capital to redeploy. As the Egyptian sales price demonstrates, we have valuable assets in Africa. However, we believe we have even more compelling opportunities in other parts of our portfolio.

Devon has the luxury today of being very opportunity rich. These opportunities comprise our low risk development projects such as Barnett Shale, Carthage and Groesbeck in East Texas, the Washakie Field in Wyoming, the Jackfish project in Canada.

Our opportunities also include increasingly successful high impact exploration program. Most notably, this includes the Deepwater Gulf of Mexico where we have assembled interest in nearly 500 lease blocks and have identified very significant resource potential. We now have six discoveries in various stages of evaluation in development, including four in the rapidly emerging Lower Tertiary trend.

We are continuing to evaluate opportunities with this inventory, and later this year expect to begin drilling the first Devon operated exploratory well in the Lower Tertiary. We also have a promising suite of exploratory prospects in Brazil and China. By divesting our assets in Africa, we can redeploy our resource, both our capital and our people, to a wide variety of excellent growth opportunities.

We will also have -- be able to enhance our per share value by utilizing the divestiture proceeds and existing cash to both retire debt and resume our share repurchase program, of course, in addition to funding our existing capital program. In summary, we believe that simply by executing our existing plan on our existing suite of assets we are well-positioned to deliver value over the next decade.

At this point, I will turn it over to Steve Hadden who will give you a more in depth review of exploration and operations. Steve?

Thanks, Larry, and good morning to everyone.

We had a very active first quarter drilling 597 wells Company-wide. 70 --78 of these wells were classified as exploration wells, of which 92% were successful. The remaining 519 wells were development well and about 99% of those were successful. We had 146 rigs drilling Devon wells during the peak of activity in the quarter and finished March with 119 rigs at work, 70 of those on Devon operated wells.

Capital expenditures in the first quarter for exploration and development on our retained properties were $1.3 billion. This was just about a fourth of our full year forecast of 4.9 to $5.3 billion.

Now, let's move to our quarterly operational highlights. Starting with the Barnett Shale field in North Texas where we continued with record-setting activity levels. We are currently drilling 32 Devon operated rigs of which 15 are in the core area and 17 are drilling outside the core, including ten in Johnson County.

During the first quarter we completed a total of 110 Barnett wells, of which 49 were in the core and 61 were outside the core. We drilled our 700th operated horizontal well during the first quarter. Our net Barnett Shale production averaged a record 730 million cubic feet of gas a day for the first quarter, up 6% from the fourth quarter average and up 28% over the year.

We are seeing solid results in Johnson County as we continue to transition into an exploitation phase. In the first quarter we put 28 new wells on line in Johnson County at an average rate of 2.7 million cubic feet a day. Two wells in Johnson County each had initial production rates in excess of 6 million cubic feet a day. The initial production rates we are quoting here are sustained 24-hour flow rates and not instantaneous production rates extrapolated to a daily rate.

We also continued to see encouraging results from 20-acre infill drilling program. Through the end of the first quarter, we had completed a total of 100 infill wells, 80 of which were horizontal. A total of 90 infill wells have been connected to the production grid and 71 of those -- of those are horizontal that came on line at an average of 2.1 million cubic feet a day.

This exceeds our original estimate of 1.7 million per day for horizontal infill wells. Infill drilling is one of the many techniques we are using to capture more of the tremendous resource potential within our Barnett Shale assets.

In the Woodford Shale in Eastern Oklahoma, we currently have 12 rigs drilling, including 5 rigs operated by Devon. We bought a total of 18 new wells on line during the first quarter, that saw initial production rates as high as 5.8 million cubic feet a day.

Moving to Rockies, in the Powder River Basin after seeing the results of our early pilot programs in the Big George, we are beginning to ramp up that activity. The Big George coals are deeper and thicker than the Wyodak, where we establish most of our legacy Powder River production.

Drilling activity will pick up during the second half of this year as we plan to drill more than 300 new gas wells. Our current production in the Powder is about 55 million cubic feet a day. We expect to exit the year producing over 70 million cubic feet a day, and ultimately expect to bring the Powder River production to over 100 million cubic feet a day in late 2008.

In the Washakie Basin in Wyoming we had four rigs running throughout most of the quarter. During the quarter we drilled 29 wills wells and bought 26 wells on to production. Devon's net production at Washakie averaged about 100 million cubic feet a day in the first quarter.

Now shifting to East Texas, we continue to advance our horizontal drilling programs in both Groesbeck and Carthage areas. In 2006 we drilled several successful horizontal wells in the Nan-su-Gail Field within the Groesbeck area. These included the Hill 9H that IPed at 26 million a day and the Crenshaw 14H that IPed at 32 million per day.

These wells are extraordinary in that their initial flow rates made them among the highest rate gas wells drilled in North America during 2006. The cost of the wells in this play vary significantly depending upon the length of the horizontal lateral and the number of frac stages.

Wells with much lower initial flow rates, as low as 5 million cubic feet a day, can deliver solid economics. With several successful horizontals under our belt in Nan-Su-Gail, we continue to apply and refine the technology in other fields in the greater Groesbeck area through the application of various drilling and completion techniques through multiple formations in multiple fields.

One of those neighboring fields where we applied this technology is known as the Oaks Field. We completed the simulation of the Everett 10H well during the first quarter of 2007 and it climbed up to about 8 million cubic feet a day. We plan to spud a second horizontal well here in June.

In the Personville Field, another field in the Groesbeck area, we successfully completed the 100% working interest Smythe 12H well which IPed at about 6 million cubic feet a day. This was our first horizontal in the Cotton Valley Line, and we plan to spud a second in June.

Our first quarter net production from Groesbeck averaged about 75 million cubic cubic feet of gas a day. We are also attempting to apply the same approach further to the northeast at several fields in our Greater Carthage area. During the first quarter we finished completion operations on two horizontal Cotton Valley sand wells we mentioned last quarter. The Griffith 10H IPed at 8.5 million cubic feet a day and the Soap 14H at more than 5 million cubic feet a day.

In addition, in April, we completed our first Cotton Valley horizontal well in the northern part of the Carthage acreage, The Taylor A9H was an especially good well that IPed at 13 million cubic feet a day. These wells are running about three times the cost of a vertical well, but appear to deliver five to six times the production rate on average.

We've now drilled successful wells in four different producing formations at Carthage and Groesbeck, that includes the Bossier, the Travis Peak, Cotton Valley Sand and the Cotton Valley Line. Reservoir performance has been very encouraging in each of these formations. The horizontal drilling and multistage fracture stipulation techniques that we are applying are challenging and very complex technology.

We are still on the learning curve and continue to improve our location selection, drilling and completion techniques. We are working towards refining our approach to deliver consistent repeatable results across our acreage position. We believe we have 70 additional horizontal locations at Carthage and as many as 200 potential drilling locations in the Groesbeck area.

Also at Carthage, we have continued with our very active vertical Cotton Valley drilling program. To execute our entire Carthage drilling program, we added three rigs during the first quarter and currently have 9 rigs running. At the end of the quarter, we were drilling the 27th well in our 102 well program for 2007. Our first quarter net production from Carthage averaged 232 million cubic feet of gas a day.

Now shifting to the Gulf of Mexico, in the Deepwater Lower Tertiary trend we are in various stages of appraisal and development at the four significant discoveries that we participated in to date. At Cascade our 50% working interest project with Petro Brass in the Walker Ridge area, we continued to work toward first production around year end 2009.

During the first quarter, we began soliciting proposals for facilities construction, including the FPSO, Subsea Trees, controls, umbilical and pipelines. These are due in the second quarter, and we expect to sanction the Cascade project and award contracts in the second half of this year.

At Jack, also in the Walker Ridge Deepwater lease area, Devon and our co-owners are preparing to drill a second delineation well to Jack No. 3 late this year. This follows last year's successful production test of the Jack No. 2 well. The group is also moving forward with the evaluation of development options. Devon has a 25% working interest in Jack.

At St. Malo, also in the Walker Ridge Deepwater area, we expect to begin another delineation well this year or early 2008. We have a 22.5% working interest in St. Malo.

At Cascade which we believe is the largest of our four Lower Tertiary discoveries, the co-owners are planning the next well operation in the unit for later this year. Cascade is located in Keathley Canyon, operated by BP and Devon has a 20% working interest.

In the third quarter we expect to begin drilling an exploratory well on an untested Lower Tertiary prospect called Chuck. This will be Devon's first operated exploratory well in the Lower Tertiary trend. Chuck is located in Walker Ridge Block 278, which is only about 30 miles from the Jack discovery.

Chuck is a large subsalt structure in about 6500 feet of water. Devon has a 39.5% working interest. We intend to drill Chuck with the Ocean Endeavor Deepwater Rig that Devon has under long-term contract.

The Ocean Endeavor is a fifth generation semi-submersible that is capable of drilling to 35,000 feet deep in 10,000 feet of water. It's currently in transit from Singapore. Following the drilling of the Chuck exploratory well, we plan to move the Ocean Endeavor to Jack and drill the Jack No. 3 that I mentioned previously.

In the eastern Gulf of Mexico, our two Merganser wells that we plan to tie into the Independence Hub are completed and equipped for production. The production platform for the Independence Hub is on location and installation operations continued throughout the first quarter. Startup is expected early in the second half of the year.

Merganser will produce into the Independence Hub at about 50 million cubic feet of natural gas per day, net to Devon interest. At Mission Deep, our most recent Miocene discovery located in Green Canyon 955 and roughly 7300 feet of water, the partners are evaluating its potential.

Turning to the Gulf of Mexico Shelf, we've had recent success in both exploration and development projects. We made a discovery at our Nectarine prospect on Eugene Island 337. The well was drilled to about 10,000 feet and penetrated the lettic sands that are produced in other wells in the field. We expect to bring the well on line in July at about 1,000 barrels of oil a day equivalent.

On the development side, during the first quarter Eugene Island 334 D3 was drilled as a follow up to two preceding wells that are producing a combined rate of 40 million cubic feet of natural gas a day. The D3 well was completed in April, and production is ramping up. It is currently producing 18 million cubic feet of gas a day and 500 barrels of condensate. Devon has 100% working interest in this well.

Moving to Canada, we drilled 307 wells in Canada in the first quarter. As we previous informed you, we elected last year to pull back on our conventional gas drilling activity as a result of the industries over heated cost environment. However, we were very active in our Lloydminster oil play in Alberta with 6 rigs running throughout the quarter.

Our first quarter activity in Lloydminster area included drilling 78 wells at Iron River, and we plan to maintain a 5 rig program for the remainder of 2007. Also in the first quarter, we completed the 10,000 barrels a day expansion to our Manatokan facility to handle our growing oil volumes from the Iron River area.

Because we expected to increase our Iron River production from the current 6600 barrels of oil per day to more than 30,000 barrels a day in 2010, additional facility expansions will be called for in the future.

At our 100% Devon owned Jackfish Thermal Heavy Oil project in that eastern Alberta, facilities construction is nearing its completion. We expect to begin steam injection at Jackfish in June, leading to first production in the second half of this year. Production will increase throughout 2008 toward an expected sustainable rate of 35,000 barrels a day by the end of next year.

At our Jackfish 2 project, engineering and budgeting work continues, and we expect to make a decision on whether to proceed with the project later this year subject to regulatory approval. Jackfish 2 has the potential to essentially double Jackfish 1, adding 300 million barrels of reserves and 35,000 barrels a day of oil production.

Moving to the international arena, the Devon operated Polvo Oil project on Block BMC 8 in Brazil remains on product for first production this year. Platform hook-up and commissioning activities are now complete, and we've had initiated drilling on our first development well.

The FPSO conversion is also complete and the vessel arrived in Brazil last week. It's expected on location once installation of the mooring system is completed. First production is planned for July, and we expect it to ramp up throughout the year to 26,000 barrels per day in 2008 net to Devon 60% working Internet.

We booked 6 -- or, I'm sorry, we booked 9 million barrels of proved reserves at Polvo in 2006 and expect to book additional reserves in 2007. Also on Block BMC 8, we drilled 3 wells during the first quarter. One well was noncommercial, and the other two wells have resulted in minor fuel extensions that could be integrated into the Polvo development.

Finally in Azerbaijan where Devon has a 5.6% working interest in the ACG Oil Field, first oil production reached 720,000 barrels of oil a day in March. Devon of ACG production averaged over 35,000 barrels a day in the first quarter. We expect to average at least 30,000 barrels a day for the entire year.

Under the production sharing contract terms end of current oil prices, we expect our share of production to be reduced in two phases to about 15,000 barrels a day in mid 2008. Under current oil prices our share production would then remain at that level.

That concludes the operation update. Now I will turn it over to John Richels to review our financial results for the first quarter. John?

Thank you, Steve.

I am going to run through a brief review of the key drivers that impacted our first quarter financial results as well as the likely impact on our results for the remainder of the year. As Vince mentioned, in accordance with accounting rules, we have reclassified the assets, liabilities and results of operations in Egypt and West Africa as discontinued operations for all accounting periods presented. I will focus my comments on our continuing operations, which will exclude results attributable to Egypt and West Africa.

Let's begin with production. Our first quarter production came in at the top end of our guidance range as we produced 52.9 million barrels of oil equivalent or 588,000 barrels per day. That's a 12% increase over the 525,000 barrels per day we reported in the first quarter of 2006.

When you examine our quarterly production in greater detail, you'll find that this growth was driven by strong performance in the U.S. onshore and international sectors, partially offset by lower production in Canada. Production from our international segment escalated by 40,000 equivalent barrels per day when compared to the first quarter last year. This growth was primarily driven by increased production from the ACG field in Azerbaijan.

In addition, the U.S. onshore region grew by nearly 30,000 barrels per day or 10% over the same quarter a year ago. Once again, the leading driver of our U.S. onshore performance was the growth from our Barnett Shale assets. In Canada where we have significantly scaled back conventional gas drilling activity, first quarter production decreased by 3% year over year.

As Larry said earlier, Company-wide volumes are expected to pick up in the second half of the year as we benefit from first production from the Merganser Field in the Deepwater Gulf, the Polvo Field offshore Brazil and the Jackfish Heavy Oil project in Alberta.

We also expect production to continue to increase from our core U.S. onshore properties. Looking to our full-year estimates, we remain confident that we will deliver on our guidance of 219 to 221 million equivalent barrels of production.

Shifting to price realizations and starting with oil, the first quarter WTI benchmark oil price averaged $58.33 per barrel, that's an 8% decrease from the first quarter of last year. Despite the lower WTI index price, Devon's average realized oil price actually increased by 1% when compared to the first quarter of 2006.

Narrowing differentials for heavy oil in Canada along with premium pricing for our light sweet oil in Azerbaijan led to the improved price realizations. Overall, our Company-wide oil price realization came in at 89% of WTI and exceeded the top end of our guidance ranges. Although our oil price differentials are off to a good start for the year, we think it's premature to make any changes to our full-year guidance.

On the natural gas side, the benchmark Henry Hub Index averaged $6.77 per mcf for the first quarter. The Henry Hub Index was 25% lower than the first quarter of 2006 but up slighting from the fourth quarter. Company-wide gas price realizations averaged 90% of Henry Hub, which was at the top end of our guidance range.

Differentials narrowed in virtually all of our producing regions, and our realized prices were especially strong in Canada and in the Gulf of Mexico. We still believe our full-year guidance ranges for gas price differentials are reasonable.

Next I want to briefly cover our marketing and midstream results. First quarter operating profit totaled $109 million. That's a $9 million improvement over last quarter. This performance was driven both by hiring processing income along with improved margins in gas transportation. For the full year we are confident in our guidance for operating profit of 390 to $430 million.

Turning to expenses, first quarter lease operating and transportation expenses came in at $430 million, or $8.13 per Boe. This is about $0.10 above the top end of our guidance range and roughly 10% higher than fourth quarter LOE rates. Approximately half of the LOE rate increase from the fourth quarter was due to increased transportation costs.

The ACG field in Azerbaijan was the primary contributor to the rise in transportation costs. While operating costs are very low for ACG, the oil transportation costs are fairly significant. In the first quarter, ACG transportation costs were unexpectedly high because the western route pipeline was shut down for repairs and production was redirected through higher cost routes. This situation will likely continue throughout 2007.

Another significant portion, about 25%, of the sequential quarter increase in LOE is attributable to ad valorem taxes. Depending on the local jurisdiction assessing the tax, ad valorem taxes are based on the value of oil and gas properties or on revenues.

The other significant driver for first quarter LOE was a very active well workover program in the Gulf of Mexico and U.S. onshore segments. We do not expect to maintain this level of workover activity throughout the balance of 2007. Looking forward we do not currently see a need to revise our full-year LOE forecast range of 1.7 to $1.8 billion. However, it now appears more likely than not that we will be near the upper end of that range.

Moving to interest expense, interest expense was right in line with our expectations at $110 million for the quarter. Of our total expense for the quarter, 22 million was interest on our commercial paper balances, which we expect to pay down following the close of our divestitures.

Looking to the remainder of the year, we expect second quarter interest expense to be flat and anticipate that interest payments will decline in the second half of 2007 as the divestiture proceeds are realized. Once we get better visibility on the closing dates of our West African divestitures, we will update our full-year interest expense estimates.

Moving to earnings, earnings from our continuing operations were an impressive $574 million or $1.27 per diluted share outstanding in the first quarter. That is a 14% increase over continuing operations from the fourth quarter of 2006.

Earnings from our discontinued operations came in at $77 million, or $0.17 per diluted share. In aggregate, our total reported net earnings for the first quarter were $651 million, or $1.44 per diluted share. As Vince said earlier, Devon's actual first quarter results were significantly better than the Street estimates, both -- both with and without the discontinued operations.

Before we open up the call to Q&A, I want to conclude with a review of Devon's overall financial position. For the quarter, cash flow from operations continued to be solid at $1.5 billion.

We utilized this cash flow along with cash on hand to fund $1.3 billion of exploration and development expenditures and about $300 million of additional capital requirements, as well as to reduce our commercial paper borrowings by nearly $350 million. We ended the quarter with cash and short term investments of $900 million and a net debt to capitalization ratio of 23%.

Looking to the remainder of 2007, we expect cash flow from operations to roughly cover our total capital demands. That will leave us with the after-tax proceeds from the African divestitures available to reduce debt and resume our 50 million share repurchase program that we suspended when we announced the Chief acquisitions last year.

Overall, we are all very excited about Devon's outlook and believe that we are extremely well-positioned to continue to grow per share value in both the near term and the long-term.

And with that I am going to turn the call back over to Vince to open it up for Q&A.

Operator, we are ready for the first question.

Thank you.

(OPERATOR INSTRUCTIONS)

Our first question comes from Tom Gardner from Simmons and Company.

Hi, guys.

Morning.

Good morning. Given your commendable growth in the Barnett, I was a bit surprised to see your sequential North American onshore gas production decline.

Could you tell us maybe what's driving that? Are there special circumstances? Are you finding onshore growth in the gas area more challenging?

This is Vince. Actually on our shore -- U.S. onshore gas production was up slightly on a daily rate basis in the first quarter.

Over the fourth quarter?

In the first quarter versus the fourth quarter, correct. And the -- we had a decline in the Gulf of Mexico, that was the Shelf where we are not attempting to offset a natural decline.

I will point out we that we have Merganser coming on in Gulf mid year at about 50 million a day net to our interest so that we will have significant growth in the Gulf overall this year. And then we are allowing Canadian assets to decline -- the gas production to decline in Canada until the investment climate is better. Those are really the drivers to the first quarter numbers on a sequential quarter basis.

Did you experience any free zones to speak of in January and February?

I'm sorry? We couldn't hear you, experience any.

Any free zones, shut in due to whether?

Yes, Tom, we had some problems in the Wyoming area up in Washakie relative to freezes up there and some problems with third party pipelines and plants but those have been resolved and we are back up on our rates up there.

Great. Thanks, guys.

Could you talk for a minute about the potential for offshore lease exploration and to what degree is this driving your exploration program and is it really a significant issue?

Yes, Tom, this is Steve again.

As we look at our offshore exploration program and we look at the issue of lease exploration, we monitor that very, very closely. And in most cases, lease exploration is not necessarily driving, it's not driving our prospect selection. In some cases it may drive some of the order in which we may drill some of our exploration wells with the slots available to us, but it really doesn't -- it really doesn't dominate that plan or that rig schedule.

Great.

Just one real quick one. With regard to first oil out of the Lower Tertiary, when is that slated currently and is it still out of Cascade?

Yes, that's right, Tom, Cascade and we are right now on target for late 2009.

Great. Thank you. Great quarter, guys.

Our next question comes from Robert Morris from Banc of America.

Good morning.

Steve, on the Chuck prospect in the Lower Tertiary, do you have an interest in that or is your interest promote that you have on that prospect?

There is a slight promote that we are paying as a result of having the 40% interest.

Okay. And who are your partners in that?

The partners are Conoco, Exxon and Maersk.

Okay. Do you have a unrisked reserve potential for that?

No, but it will be -- we have disclosed that these prospects are in the range of 300 to 500 million barrels of vigor and it's well win within that range.

Okay.

Second question, in Canada, several of your peers have indicated greater than anticipated drop in services costs so far and have indicated that if continues they may ramp back up in Canada drilling later this year.

Given the sharp pull back that you've undertaken there in Canada, what are you seeing and is it possible that you also may look to ramp up later in the year if service costs continue to moderate there?

Yes. With the asset base we have up there, and I think we mentioned this on the last call, we are very -- still very pleased with the resource base that's up there, the potential EURs and the production rates we can get out of that gas drilling program, and as you've alluded to, those costs simply got too high for us to continue to invest our money there versus other alternatives we have in this very broad portfolio.

When we look at the costs in Canada, we see them coming -- leveling off and coming down. To what degree we will know much better over the next month or so as we begin to negotiate service pricing for the Canadian business. Of course, that happens about two times a year and we will get a much better fix on that coming in. We did see a reduction in the rate utilization and as you mentioned, we along with other people who operate in that basin, have pulled back significantly on our capital.

But it remains to be seen how far that's going to be. And if it's -- if it pulls back enough, we certainly would consider putting more money back into that business because we think it's a very good business from a gas standpoint. But if it doesn't pull back enough we will continue to fund some of these other opportunities until the industry corrects itself up there.

Great. Thank you.

Bob, I just might add that it is not a question of whether we will pull back, it's just a question of when, and that's hard to predict. So sooner or later we will ramp up. Whether or not it will happen this year or later it's hard to predict, but it will happen.

Our next question comes for Gil Yang from Citigroup

Hi. Steve, I was wondering about Carthage and Groesbeck as an example, the horizontal locations that you talk about, do those supercede existing vertical locations or are they supplementary to vertical locations?

Yes, Gil, the best way to think of it is they are supplementary. In essence we are drilling horizontal wells that move down potential vertical well locations.

In other words, we may move along in an area that -- where we are contacting reserves that otherwise would not be produced and we are doing it by drilling along that horizontal path covering several different locations where vertical wells don't currently exist.

And you would not have drilled a vertical well?

And we would not have drilled a vertical well in that immediate area, right.

Okay. Second question is, could you give us some sense for -- your existing plays seem to be working quite well, could you give a sense of what kinds of new opportunities you're looking for onshore in North America, other shale plays or other type sands formations?

Gill, we are pretty pleased with the position that we have right now and, of course, those positions that really are working well for us include both type gas, the shale, and you heard us talk a little bit about the CBM up in Wyoming. We are continuing to look for opportunities to add to our core positions in those areas or in those trends. And we've done that over time and we continue to do that. We did that last year.

We will continue to do that this year. And simply try and build with bolt on acreage or small bolt on asset deals where we can build those positions. We are continuing to look across North America and leveraging the competency that we have in the type gas and shales and we are seeing some interesting opportunities that we are running through a very disciplined screening process.

And that screening process includes, number one, having materiality relative to Devon and being able to to have significant running room and access at reasonable cost to a good acreage position and, number two, having the capability to execute on that program and ramp up production in those areas once we decide the areas that we want to invest in.

Okay. Thank you.

Our next question comes from Ellen Hannan from Bear Stearns.

Thank you.

Just a couple of follow up questions for Steve. On the horizontal locations that you've got in both Carthage and Groesbeck, can you talk about whether you are targeting specifically the Bossier, the Cotton Valley Sand or the Cotton Valley Line?

And then as a follow up to that, can you give us an idea of your completed well cost to date and also the production history and what you've seen from some -- a couple of those wells that you completed last year?

Sure.

A couple things, Ellen, number one as it relates to the formations, we have drilled horizontal wells in the Cotton Valley Sand, in the Cotton Valley Line. We've drilled them in the Bossier and we've drilled one or two in the Travis Peak, which is a big shallower and a lower pressure, a little bit different animal.

And we've had reasonable success in those areas. In other words, when we look at the performance relative to what we would expect the reservoir to give up, we are very pleased with those results to date. The wells vary quite a bit, as you can imagine, based on how long the horizontal length is, how deep the formation is, how we choose to complete the well relative to the -- relative to the packer system or the iron that we put in the hole.

And then, of course, how many frac stages we may choose to design into the well along that horizontal section. That being said, roughly, we look at numbers that can range from $5 million to as much as $12 million for these horizontal wells. And generally what we see, I think we mentioned in Carthage is a great example, where we may see a doubling of the cost or 2.5 times the cost, but we will see rates that could be as much as five times the rate of a vertical well.

So we get those good multiples, good economic leverage. And we are very pleased with the results to date. We are relatively early in the play, if you want to look at it broadly as a play and horizontals in East Texas in these tight gas formations.

We are intentionally going in and doing, trying these different formations at different locations and trying different completion techniques and different drilling designs in order to optimize the program early so we can move to a more aggressive development phase later this year or early next.

Any comments on for example the Hill No. 9H was one of the wells in Groesbeck, what's the production history look like? Is it following a curve that you would anticipate or what's the decline on that?

The ER is pretty strong. As you can imagine with these being tight cast wells, they decline rapidly initially. They can decline as much as 60% in the full year first year. Some of these higher wells that have a lot of pressure behind them initially decline a bit faster, but they also begin to go exponential.

In other words they begin to decline at a lesser and lesser rate over time. So they are really performing as we would have expected and that's why we are continuing to drill the program.

Okay. Just one more for me, switching now to the Deepwater. You are talking about sanctioning Cascade this year. Will this allow you to book reserves?

No. We don't anticipate booking reserves with the sanctioning by Petro Brass and Devon relative to the requirements of the SEC to book reserves. So we will take a closer look at that, but we don't think the sanctioning event this year will cause us to book Deepwater reserves this year.

Great. That's it for me, thank you.

Our next question comes from John Herrlin from Merrill Lynch.

Yes, hi. A couple for Steve to start with. With Chuck, is it a three-way, four-way, what's the structure?

It's a -- conceivably you could talk about it in terms of a four-way, but we are not going to talk about any details about the structure in and of itself, but generally it has the characteristics of a four-way.

Okay. You didn't mention the Woodford Shale at all, were you active at all in the first quarter there?

Yes, sir. I think we mentioned just very briefly in the prepared remarks. We were active in the quarter. Right now we have 5 rigs running on an operated basis.

We had 12 rigs running in total through the quarter. We had 18 new wells that came on line, and we saw initial production rates as high as 5.8 million cubic feet a day on the initial tests.

Must have missed that.

Last two for me. Gulf of Mexico prices, John Richels, you had a premium to Henry Hub, any particular reason or just marketing issues?

I'll get -- Darryl Smette is here, John, we'll have Darryl address that.

Yes, John. It really was a combination of both, some of those markets were fairly strong especially as we got to the latter part of January and early February, since most of that gas we shipped back east, of course, you know the cold weather propelled prices back there, so that helped in the area.

And then a lot of the gas that we brought on that Steve talked about actually had higher BTU content. It was a combination of little bit better quality and market movement from last part of January through practically the whole part of February.

Okay. Thank you, Darryl.

Last one for me is on your gathering system, I guess this one is for Larry, we are seeing a lot of MP company's talking about doing MLPs on tolling type assets. Clearly this is an important asset for you but it's not really valued in your stock price, your gathering system in the Barnett.

Is that something that you would considering doing an MLP on, Larry?

That's a question that we have dealt with now for several years, in fact, ever since we bought Mitchell in 2002, and that's one we will continue to evaluate and if the legal situation makes sense to us, it's certainly something we can consider. So far we've elected not to, but I would never want to say never.

Okay. Thanks, Larry.

Our next question comes from Richard Moorman from Capital One Southcoast.

Good morning, gentlemen, congratulations on another great quarter.

Just wanted to follow up quickly on a couple things. First of all in the Carthage area of Cotton Valley, these are all Cotton Valley Sandstone horizontals?

Yes. The Cotton Valley wells we've been referencing to go date are Cotton Valley sand wells in the Carthage area.

Super.

Not to give away any trade secrets, but are these still targeting the middle of the sands, the data sand stone?

We, we probably aren't going to talk about that in detail, but they've been targeting, we drilled one to the south, drilled one up to the north. They are targeting few different areas of the Cotton Valley Sand.

Okay. Fair enough. And going forward from here, you previously budgeted 14 for the year. I guess is it fair to say still on track?

I'm sorry, could you repeat, 14 --

I'm sorry, you previously budgeted 14 horizontals here for the year. You have a great budget for the year here, $750 million. Just wanted to make sure the 14 horizontals were still planned.

We are on track for that and with continued success we will do at least those.

Super.

Just quick shift to the Woodford, you have had some great results there up to 5 million per day you mentioned. Just want to do see, would you be comfortable saying anything about the type curve in that play, is that a 3 bcf reserve potential for you.

We think we average and are relatively early in the play and we like to look at performance in order to really finalize the UR numbers, but right now we are seeing averages around 2.5 to 3 bcf on a typical Woodford well. That can change over time as it has as we've had more success in the Barnett but right now we are saying 2.5 to 3 bcf.

Okay. And with the Woodford, of course, the drilling costs have always been high for many operators there. Do you see air drilling doing a lot of good for you there going forward?

Yes, we see multiple improvements over time. Right now our cost of running about 4 to 4.5 million on a well basis. And we are pleased as to where we are today, but we'd like to continue to improve those numbers and drive those costs out a little bit further.

Super. Sounds like you have better costs than most people in the play. Thank you again for the questions and good luck in the second quarter.

Thank you.

(OPERATOR INSTRUCTIONS)

Operator, it looks like we don't have any more questions in the queue, so we will go ahead with some closing remarks.

Well, thanks everyone for your attention. Just a quick summary of where we think we were.

The Company had a very solid quarter with earnings from continuing operations being up 14% over the fourth quarter of '06, 12% as reported. First quarter production increased 12% over the first quarter of 2006, very solid production growth. Fourth consecutive quarter in a row from continuing operations.

All of our development projects that underpin this production growth remade on schedule. Our plans to divest in Africa are also on schedule with the sale of Egypt already inked at 375 million and we cannot be more excited about our high impact projects, particularly in the Lower Tertiary that will drive our growth well into the next decade.

Thank you very much for your attention to Devon, and we look forward to talking to you again in August. Take care.