德文能源 (DVN) 2004 Q2 法說會逐字稿

Hello, and welcome to Devon Energy Corporation second quarter earnings conference call. At the request of Devon Energy this conference is being recorded for instant replay purposes. At this time, I would like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you. And thanks to everyone for joining us today for Devon's second quarter 2004 conference call. I've got just a couple of introductory remarks, and then Larry Nichols, our Chairman and CEO will review the highlights for the quarter. Following that, our President, John Richels will cover our operations, and then our CFO, Brian Jennings will review the financial results and outlook, and then we'll open it up to questions. As is our usual practice, we'll limit the call to one hour. But we'll be available for follow-up questions after the call. Before I turn the call over to Larry I have got just a couple of compliance items to cover. First, I want remind everybody that the call information we provide today will include forward-looking information, and for a discussion of risk factors that could cause our actual results to differ from these forward-looking statements, you can refer to our Form 8-K that we filed on May 24th, that provided our updated 2004 estimates. However, we will be updating our guidance again, and filing a new Form 8-K in the next few days. So look for that to come out. The second compliance item I want to cover pertains to non-GAAP performance measures. We used some of those in the call, and the current disclosure rules require that we provide reconciliation for any non-GAAP measures that we've referenced to the closest GAAP measures, and to explain why the non-GAAP measures are useful. To see those disclosures, see the Press Release that went out today, it's included there. If you don't have a copy, you can retrieve a copy from our website. I might mention, we've got a new website, same address, www.devonenergy.com. With those items out of the way I'll turn it over to Larry.

Thanks, Vince. Before we get down to the business of the quarter, let me just say that we're delighted to welcome Steve Hadden as a member of our Senior Management Team. As we announced on June 25th, he has joined the Company as Devon's Senior Vice President of Exploration and Production. Steve is a 20-year industry-veteran with a proven record of success. He will oversee our 2 billion-plus annual exploration and production capital budget, and lead our exploration and development organization. We're delighted to have him. Now, to the quarter. The second quarter was another terrific one for Devon. We recorded net earnings of 502 million, 41% ahead of last year. Earnings per share were $2.02, just above the first call consensus of $2.01. Oil and gas production averaged 684,000 barrels of oil equivalent per day, up 11% compared to 2003. We closed our merger with Ocean last year in April of 2003. So the second quarter of 2003 results do not reflect the entire quarter for Ocean's production.

However, if you look at second quarter 2004 production, it also is higher on a comparable pro forma basis, up about 4% over what Devon and Ocean produced combined in the second quarter of 2003. As we forecasted in our first quarter conference call, sequential quarter production trailed the all time record we set in the first quarter of this year. As expected this was largely driven by the early cost payouts on 2 international projects Zafiro and Panyu. As you may recall higher oil prices accelerated the recovery of our costs in these projects, and like most international production sharing agreements, Devon's share of production was reduced once we reached payout. Our deepwater Red Hawk gas field came on in July, and that lined up to production in the second half of the year. Red Hawk is now in full production, delivering 60 million cubic feet a day net to Devon, about 10,000 barrels net to us. I would like to acknowledge the contributions of Devon and Kerr-McGee teams who worked on the Red Hawk project. Kerr-McGee operates this project and its completion just 2 years from sanctioning was really a notable accomplishment.

Total quarterly revenues reached 2.2 billion, including 377 million from another strong performance by our Marketing and Administering Operations Division. Cash flow before balance sheet changes matched the 1.2 billion we booked in the first quarter. After funding second quarter capital expenditures of 765 million, and this includes both upstream, midstream, and corporate capital expenditures, and after repaying 760 million in debt, we held 1.1 billion in cash at the end of June 30. Through yesterday, our cash balance had grown to approximately 1.4 billion. So we are quickly approaching our target that we've had all year of having 1.6 billion of cash on hand to cover all of our debt maturities in 2005 and 2006. At our next Board meeting, which will be in September, we expect our Directors will consider offering these for the free cash that we expect to generate over and above this 1.6 billion. As we have mentioned before these alternatives include, both increases in cash dividends, as well as a share repurchase program. John Richels will discuss operations in more detail, but I want to point out 2 significant second quarter operational events in addition to the start-up of Red Hawk.

First, Devon reached a milestone in the Barnett Shale in June when it brought our 100th horizontal-well on stream. The second important event I want to mention is the success of our appraisal well on the St. Malo prospect deepwater Gulf of Mexico. Although, we are still evaluating data from this well our optimism is growing for St. Malo, and more importantly, the implication for Devon's prime acreage and prospect position in the emerging lower tertiary trends. In addition to St. Malo, we are evaluating one and drilling in another lower tertiary exploratory well and expect to participate in an appraisal of our 2002 discovery at Cascade later this year later or early next year. We are not likely to book any meaningful reserves from these projects in 2004. But if this momentum continues to gather, the lower tertiary trend will be a very significant growth driver for Devon for many years to come. Before I turn the call over to John, I want to remind you that Devon's 2004 executive briefing is scheduled for September 28th in New York. Analysts and Portfolio Managers will be receiving invitations shortly. For our broader audience this half-day event will also be webcast. The meeting will begin at 8 a.m. Eastern time, and a link will be available from Devon's home page to allow you to access this meeting from your computer. Now, with that I will turn the call over to John Richels.

Thanks, Larry. The second quarter was another active one for Devon from a drilling perspective. We had 109 rigs running at June 30th, with 98 of these in North America. To put that into perspective, about 6% of the total rigs running in North America were busy drilling Devon wells. Moreover, 70 of the 109 rigs we had working worldwide were drilling Devon operated wells. This activity level was up slightly from the 102 rigs we had working at the end of March. Capital expenditures for exploration and development projects were 629 million in the second quarter, bringing the total to roughly 1.3 billion for the first 6 months. While that's more than half of our full-year budget, the expenditures in the first half reflect the front-end weighting caused by the Winter Drilling Program in Canada. We drilled 398 wells company-wide during the second quarter or an average of more than 4 wells per day. 36 of these wells were classified as exploration wells, and 94% of the exploration wells were successful. The remaining 362 wells were development wells with about 99% successful. So we had another great quarter with the drill bit.

I'll begin the operational highlights onshore with the Barnett Shale field in North Texas. We had 14 operated rigs running at June 30, with 10 rigs drilling horizontal wells. During the quarter we completed 20 horizontal and 16 vertical wells, and initiated production from 25 horizontal and 30 vertical wells. Devon's second quarter Barnett Shale production averaged 55 million cubic feet equivalent per day, which is down about 3.5% from the 575 million cubic feet per day that we averaged during the first quarter of 2004, but up 7% from the 520 million a day that we averaged in the second quarter of 2003. As Larry previously mentioned, we tied in our 100th horizontal well in June, and these 100 wells are producing a combined 120 million cubic feet of natural gas per day, or a little over 20% of Devon's field-wide Barnett Shale production. 39 of the 100 horizontals are outside the core area, and these wells are averaging about a million cubic feet per day, per well. The more recent horizontals have tended to be better producers than the earlier horizontals that we drilled outside the core. For example; a noncore well in Johnson County that came on-line in June had an initial production rate of 3.7 million cubic feet per day. However, that well is our best noncore completion to date, and is clearly not a typical noncore well.

In Denton County, which you will recall is just to the east and northeast of the core area, we brought on 7 noncore horizontal wells in the second quarter with IPs ranging from 1.25 to 3.3 million cubic feet per day. In addition we continue to bring on some very strong wells inside the core. By way of example, we brought on 3 core area horizontals in June that came on line at an average production rate of about 4.6 million cubic feet per day. In addition to new drills we've also begin to refract a number of older wells in the core area. These are vertical wells that were originally completed and stimulated with with a light sand flak. So far the results have been very encouraging. For the year-to-date we've refract 19 wells that were originally completed with a light sand flak, and have on average increased production by about 200 Mcf per day per well. What's also notable is that the refracts don't just add production they also add incremental reserves. On average were seeing 2/10s to a 1/4 of bcf of new reserves per well at an average finding and development cost of about $1.00 to $1.25 per Mcf. We plan to refract another 19 or 20 wells this year way, out 50 in 2005, and more than 250 per year in each of 2006, 2007, and 2008. One of the aspects of the Barnett Shale that has intrigued us from the beginning has been the potential for increasing reserves and production with refracts so we'll be monitoring these early results very closely. Another approach that we are studying in the Barnett Shale is to increase overall field recoveries as drilling horizontal wells inside the core as a means to further downspace the field. Because we believe the drainage pattern of typical vertical Barnett wells is elliptical, we are left with open paths between groups of vertical wells where we can get fit in horizontal well force. These could be high-rate wells and we are currently completing the first of these intel horizontals.

Moving to another nonconventional gas asset, our Powder River Basin Coalbed Natural Gas Plant in Wyoming we're currently running 3 rigs. We've drilled 62 new wells and deepened 6 others this year in the Powder. 46 of the 68 wells have been deep Wyodak or Big George wells. In our House Creek area, we've obtained Federal drilling permits to begin a 21-well program all to be drilled to the deeper coals. Devon's net production from the Powder River Basin is running about 78 MMcf per day. In the San Juan Basin in New Mexico the approval of field-wide downspacing is allowing us to accelerate drilling activity. We had 3 rigs running for much of the second quarter, and have now drilled 16 coalbed natural gas wells and 10 conventional wells year-to-date. Plans are to drill a total of 70 coalbed wells and 21 conventional wells. This level of drilling should allow us to reverse the natural decline and increase production from our current net rate of about 45 MMcf per day.

Elsewhere in New Mexico, we continue to have good results from our Permian Basin deep gas play. For the year-to-date, we've completed 11 Southeast New Mexico deep gas wells which are flowing a gross combined 37 MMcf per day. We've upped the rigs running from 3 to 5, and have decided to increase our 2004 program in the area to 27 wells. We've purchased some additional acreage, and have about a 50% working interest in the play. In East Texas, at our Carthage area, we've increased our net production by 8% from the first quarter to 175 MMcf per day. We've drilled 18 new Cotton Valley wells, and recompleted 14 wells at Carthage which on a combined net initial production basis have added 37 MMcf of natural gas production per day. We added a 4th rig to this program earlier this year, and we plan to drill and complete 34 more wells by the end of 2004. In the Washakie Basin in Wyoming, we're gearing up activity again after wild life stipulations were lifted in June. We plan to drill 52 wells in the Washakie this year, including 2 exploratory wells in the north-end of the field. In our combined Rocky Mountain and Permian Basin areas we expect to keep 25 rigs running for the remainder of 2004.

Now moving to the U.S. offshore. As Larry mentioned our Red Hawk sales par and the deepwater Gulf of Mexico came on line in mid-July. We should begin to see a production boost from it in the third quarter. The 2 Red Hawk wells are currently producing at a facility capacity of 120 million cubic feet of gas per day. And the facilities are capable of expansion in the future should additional field drilling and satellite discoveries warrant it. Just as a reminder Devon has a 50% working interest in Red Hawk. In the Nansen/Boomvang complex we restored production in late June to the East Boomvang's 688-No. 8 well that we reported was shut-in due to equipment problems in our first quarter conference call. Combined production from Nansen/Boomvang averaged about 36,000 equivalent barrels net to Devon's interest in the second quarter, and in September, we will add 2 additional satellite wells, one being an oil producer, and one a gas producer to the Boomvang facilities. Our Magnolia Deepwater Project at Garden Banks 783 remains on-track for a late-year start-up. The Tension Lake platform is now sailing out to location, and Devon's share of production from Magnolia is expected to ramp-up to between 9 and 12,000 equivalent barrels per day in 2005.

On the offshore exploration front, we're, as Larry mentioned, we're very pleased with the results of our St. Malo deepwater appraisal well. As you may recall St. Malo was a lower tertiary discovery that we first announced in 2003. The appraisal well is about a mile east of last year's Discovery well on Walker Ridge block-678. The appraisal well encountered 400 feet of net oil pay, while the Discovery well logged about 450 feet. We recovered a tremendous amount of data from the appraisal well, and the technical teams are reviewing the data and determining what the next move will be. Devon has a 22.5% interest in St. Malo. On another lower tertiary prospect, the Jack prospect on Walker Ridge 759, operations have been temporarily suspended and the rig has been released, and we and our participators are currently evaluating the results. Devon's participation in Jack completes a four-well program in our joint venture with Chevron/Texaco that earns us 25% of Chevron/Texaco's interest in 71 deepwater blocks. West of St. Malo and Jack we're currently drilling below 19,000 feet on the Sardinia prospect which was spud on July the 4th. Sardinia, another lower tertiary prospect is located on [Keefley] Canyon 681, and we have a 35% working interest in that prospect.

Now moving to Canada. We continue to see some positive results with second quarter oil and gas production up 5% year-over-year, and 3% above the first quarter of the year. This production growth was in spite of a very wet spring and some resulting operational delays. Now that things have dried up a bit, our summer drilling programs are under way in most areas, and we plan about a 15% greater activity level this summer than last. At the end of June, we had 27 rigs running throughout Canada, 20 operated by Devon. This is up from about 8 rigs running at the end of April during the winter break-up season. One area where we are well along with our summer drilling program is in the Lloyd Minister area, where as of the end of June, we had completed 86 wells of the 148 wells planned for the summer. Devon's net production is currently running over 21,000 equivalent barrels per day from the Lloyd area.

Looking now outside of North America we had 8 rigs running at the end of the second quarter, and during the quarter we drilled a total of 21 wells on international projects. In China, on the Devon operated Panyu project, we added 5 more producing wells in the second quarter, 19 wells are now on-line. 11 wells in the 4-2 field and 8 wells in the 5-1 field. Field-wide production averaged 85,000 barrels of oil per day in June, which translates to about 20,000 barrels per day net to Devon. This project has produced a total of 15 million barrels of oil in just 10 months and is a real success story both from a reserves and from a production standpoint. Recent drilling results has significantly increased our reserve estimates and should allow us to maintain our production plateau for longer than previously expected. In West Africa, at the Zafiro field and Equatorial Guinea we experienced a drop in Devon's share of field production in the second quarter. Although gross field production held at about 275,000 barrels per day during the quarter Devon's net share declined from about 57,000 barrels per day in Q1, to about 40,000 barrels per day in the second quarter. The biggest driver was reaching certain cost recovery triggers in accordance with the production sharing contract. In addition, an out-of-period adjustment and the timing of actual liftings between the two quarters exaggerated the quarter-to-quarter difference in Devon's reported share of production. We believe gross field production can hold steady for the remainder of 2004 at above 275,000 barrels per day. And our net share should be in the 40 to 50,000 barrel per day range. We don't expect to encounter another significant change in net interest until mid-2005 when accumulative production milestone will trigger about a 13 or 14% reduction in Devon's Zafiro production.

On the West African exploration front we have exploratory well planned for late in the third quarter on block-P in Equatorial Guinea. In addition to the well on block-P we plan to spud wells round-year-end to test prospects on both block-10 in Angola and on block-256 in Nigeria. The timing of the exploratory wells that were planned for block-24 in Angola, and block-N in Equatorial Guinea has slipped slightly causing the drilling of those wells to be moved into 2005. In Egypt, we are drilling an exploratory well on the Kefron prospect in the Southeast July concession. This is the first well in an 8-well agreement we entered into recently with Santos Limited of Australia. Santos participation will earn Santos an equity interest in our Southeast July [Rezeberog] and North [Zibaig] concessions. This agreement was reached on commercial terms that we are quite pleased with and importantly will allow us to continue drilling at a brisk pace. So with that, I'll turn the call over to Brian Jennings who will now cover the financial results.

Thank you, John. Before I begin my discussion of our second quarter 2004 financial results, I want to remind everyone that our merger with Ocean Energy closed in April of 2003. Consequently, our second quarter 2003 results do not reflect the full impact of the Ocean merger. Starting with production, our second quarter 2004 production of oil, gas, and natural gas liquids totaled 62.3 million barrels of oil equivalent or 684,000 BOE per day. That was right in line with our forecasted guidance. This represented an 11% increase over the 615,000 barrels per day we reported in the second quarter of 2003. Looking at our production growth on a pro forma basis, when you add Ocean's second quarter 2003 production prior to our merger of 3.8 million barrels to our reported results, you get total second quarter 2003 pro forma production of 657,000 barrels per day. So on a same-store sales basis, we increased second quarter production in 2004 by 27,000 barrels per day, or a little over 4%. On a sequential quarter basis, consistent with the guidance we provided in our first quarter conference call, production decreased by 19,000 equivalent barrels per day. As mentioned, this was driven principally by payouts at our Zafiro and Panyu fields. For the third quarter we expect production to range between 61 and 63 million equivalent barrels. In the fourth quarter with a full-quarter's contribution from our Red Hawk field, and with our Magnolia development coming on-line, we expect our production to again climb. This production profile is consistent with our previous guidance. For the year we again confirm our full-year production guidance of 251 to 256 million equivalent barrels.

Before we get into expenses, lets look briefly at price realization. Looking first to natural gas prices. In the second quarter of 2004, the benchmark Henry Hub gas price averaged $6 per Mcfe. That price was 60 cents per million greater than the index average in the same quarter of last year. For Devon, our average price realization improved 62 cents to $5.29 per Mcfe in the quarter. Our floating prices were within our expected rages in all of our reporting areas, and the impact of our natural gas hedges was insignificant. Looking next at oil price realizations, WTI averaged $38.26 per barrel in the quarter. This was $9.29 greater than in the second quarter of last year. Devon's realized oil price in the quarter was $28.04 an improvement of $2.62 per barrel over our second quarter 2003 results. There are several reasons while our realized price increased less than the increase in the benchmark. First with oil prices near record highs we have been negatively impacted by our 2004 oil hedges. These transactions put a sealing in the high 20s on about 65% of our 2004 oil production. We have fewer hedges in place for 2005, covering only about 72,000 barrels of oil per day. To put that in perspective, that's about a third of our current daily oil production.

In addition to the impact of hedges, second quarter differentials for our floating price oil volumes also widened. Our second quarter company-wide floating price realization was $4.32 below WTI compared to $2.61 per barrel below WTI last year in the quarter. This was driven by a shift in our production mix coupled with widening differentials for our Canadian oil production. In Canada our production traded at a discount to WTI of $8.76 per barrel in the second quarter. This differential was greater than our full-year guidance of 5.50 to 7.50 per barrel, and was more than twice last year's differential of $4.32 per barrel. As we look forward, this differential has begun to narrow. However, as a result of the differential we experienced in the second quarter, we are adjusting our full-year guidance expecting our Canadian price realization to average 6 to $8 per barrel under WTI. While second quarter Canadian oil differentials were wider than expected U.S. differentials were narrower than we forecasted mitigating some of the impact of the Canadian widening. Combining the benefit of higher production with higher oil and gas prices our oil and gas sales revenue climbed 25 percent over the second quarter of 2003 to $1.8 billion. In addition to strong upstream performance in the quarter our marketing and mid-stream results once again outperformed expectations, delivering second quarter margin of $78 million. This performance was driven principally by higher than forecasted product prices. Following our first quarter results, we increased our full-year margin guidance, that is revenues less associated expenses, to 250 to $270 million. Based on our second quarter results and our outlook for the remainder of the year we again increasing our margin guidance for 2004 by an additional $30 million, to a range of 280 to $300 million.

Moving now to expenses. Our second quarter results were very encouraging with most expenses falling at the low-end our below our guidance ranges. First looking at operating costs. Unit lease operating and transportation expenses came in at $4.92 per barrel. Below the bottom of our full-year guidance range of $4.96 to $5.18 per barrel. Looking at the full-year, we now expect to come in at the low-end of that range. Moving to G&A expenses, our general and administrative expenses came in well below our guided range. G&A expense was 70 million in the most recent quarter, including a $5 million one-time charge for abandoning office space if Calgary. The $5 million charge reflects the completion of the consolidation of all of our employees in Calgary under one roof. Even with this one-time charge, second quarter G&A expense declined $23 million when compared to the second quarter of last year, and declined $7 million when compared to our first quarter results. This improvement reflects continued realization of synergies from the Ocean merger and the absence of unusual items in this quarter's results. Our outlook for the third and fourth quarters is for G&A to run about $74 million per quarter. Taking this into account we are lowering our full-year 2004 guidance for G&A by $20 million. We now expect full-year 2004 G&A expense to come in between 285 and $305 million. We remain, however, focused on reducing G&A, and hope to be able to wring out additional costs as we go forward. Our capitalize G&A came in at 42 million for the quarter right in line with our guidance.

Our second quarter DD&A rate was $8.86 per equivalent barrel. This result was below our full-year guidance of $9 to $9.20 per barrel. The lower rate reflects improved finding and development costs in the U.S. and Canada, and a decrease in the Canadian dollar exchange rate. With the remainder of the year we now expect DD&A to come in at the low-end of our full-year forecast range. Interest expense came in at 134 million for the second quarter. This included a $16 million noncash charge related to the early repayment in the second quarter of our acquisition credit facility. This charge represented the acceleration of the amortization of fees we incurred securing this facility in 2001. For the remaining 2 quarters of 2004, we now expect interest expense to range between 115 and 120 million per quarter. One expense item that did increase in the second quarter was income taxes. Our second quarter 2004 taxes were 270 million, or about 35% of our pre-tax income. Included in this total was a one-time $28 million benefit due to a change in the Canadian tax law. Had we not had this one-time benefit, our second quarter income taxes would have been 298 million, or approximately 38% pre-tax earnings with about 1/3 of that amount deferred. This is in line with what we expect for the remainder of 2004. Cutting all the way to the bottom line, we reported net earnings for the second quarter of $502 million, or $2.02 per diluted share, right on top of the first call consensus. Shifting to cash flow, in the quarter we reported cash flow before our balance sheet changes of 1.2 billion, right in line with our first quarter results.

As Larry mentioned in his opening remarks, during the quarter we repaid 760 million of debt, bringing our total debt repayments for the year to 971 million. In the quarter, our operations generated almost 400 million of free cash flow, and he we ended the quarter after debt repayment with 1.1 billion of cash in the bank. A net debt to cap in June 30, dropped to approximately 34% from almost 40% at the start of the year. Looking forward, we will use our cash, which today totals about 1.4 billion, and our free cash flow to retire in the next 24 months, 1.6 billion of maturing obligations. Our action to reduce debt and our pledge to retire upcoming maturities is consistent with our desire to maintain financial flexibility while continuing to strengthen our balance sheet. In summary, in the second quarter we met our production guidance and delivered year-over-year organic growth of 4%. Full-year guidance remains intact. We reported another strong quarter of marketing and mid-stream results, causing us to raise our full-year margin guidance for the division by $30 million. Finally, we bucked the industry trend of rising costs delivering LOE, G&A, and DD&A rates at or below our guidance ranges. And in the case of G&A we reduced our full-year guidance by $20 million. All in all solid performance. And with that I'm going to toss -- give the call back to Vince and we'll open it up for Q&A. Thank you.

Okay, operator, we're ready for our first question.

Thank you Mr. White. At this time there will be a question-and-answer session. (OPERATOR INSTRUCTIONS) One moment while the questions register. All right. Our first question comes from Mr. David Khani with Friedman, Billings, and Ramsey.

Yeah, hi guys question on the Barnett Shale, maybe John. How much running room do you have for horizontals within the core area?

Hi, David. David, we have Brad Foster who is our General Manager of our Central Division which manages that asset and I think I'll turn that over Brad to answer the question.

Hey, David.

Hi.

Inside the core area right now we'll drill about probably in the neighborhood of 60 wells this year. We think right now we can keep that up for another 2 or 3 years. We are looking at different ways, as Larry -- I mean as John mentioned, we're looking also at drilling some longitudinal wells inside existing drainage patterns. And one piece I'll just point out to you, the Barnett is a huge resource base, and we're looking at longitudinal wells, we're looking at horizontal wells, we're also looking at seismic data, we're looking at simulation models, core data, a number of different areas to try to sit there and really try to increase the recovery out of the core area. If you remember, we sat there and quoted numbers in the neighborhood of 10 to 15% recovery, and the important thing, I think, everyone needs to understand inside the core is every 1% increase in recovery you make inside the core means about 230 BCF of recoverable reserves or about 40 million to Devon. So that's kind of where we're at. We think we have another 2 year. We're hoping we can sit there and apply technologies and expertise and continue to sit there, and be able to sit there and get more reserves out of that vast resource base.

And what's the recovery rate you're at now you think?

I think it all depends on what people are using for BCF per square mile in place. But right now we feel we're somewhere in between the 10 to 15% range. And you can argue that is it 12 or is it 13. But it's somewhere in that neighborhood, which means that you have about 85% reserves in place that aren't recoverable, and that's where the big advantage is down the road of trying to figure out how you get more out of this resource base.

And what do you think you can get it to looking down maybe 3 to 5 years down the road? Can you -- from -- let's say 12% or so, where do you think you would go?

I think, we have a target of where we're trying to sit there and see if we can sit there and increase that thing with 5% over the next 5 years with technology. But I mean that's just a pure guess right now. So that's where we are concentrating our efforts. And I would be hesitant to give you an exact number.

But the bottom line David, I think is that between the drilling that we see, the additional infill opportunities, and the advent of technology we see a lot of running room, both inside and outside the core in the Barnett Shale field.

And the refracts that you're doing there obviously, they're all in the core area, right?

Yeah. Right now all the refracts we're doing are inside the core. I mean, you have to go through a number of years before the pressure depletes before you go ahead and refract an area. So, if you're able to refract the noncore area it will be about 5 years from today, probably.

Okay. Great. And then, John, in the release, there were 4 exploration wells drilled. It looks like 75% success rate. What was the dry hole?

In what area, David? We didn't hear you.

You just said in the U.S., you had 4 exploration wells, I think was mentioned in the statistics.

David, I believe that was one of the -- that was a shelf well.

That was a shelf we will. Okay.

Yes, sir.

Okay. Great. Thank you.

Our next question comes from Van Levy with CIBC World Markets.

Good morning, gentlemen, how you?

Good.

A lot of questions on conference calls about the Barnett Shale. Can you give us a sense of what your reserves there are, how many locations you think you have within and outside the core area, and what amount of those locations have been booked?

I think we've stated before outside the core was somewhere in the neighborhood of 1.3 to 1.8 BCF, and --

For location.

Yes. And then from the standpoint overall trend somewhere in the neighborhood of 1.5- to 2-Ts. I would say right now that our PUDs or what we put on the books or minimal at best. We probably have in the neighborhood of 10 to 20 locations booked, and that's it.

Okay. And then you -- my understanding is you have roughly 550,000 acres within the trend, and somewhere around 120,000 in the core? Is that correct?

110,000 in the trend, of which 390,000 is outside the core.

Okay.

Van, to your original question, we have about 1.3 TCF booked at the end of last year, and that's essentially all core. Very little booked outside the core area as of December 31, 2003.

And again, what is your view now for core reserves per well?

It's very similar to the guidance we gave you before. You know, we've always said it's somewhere in the neighborhood of 2 to 2.5 beats per well, and that hasn't changed any. We're thinking on the -- I'm talk to you on the horizontal side. On the horizontal side we feel very comfortable with the 2.5 BCF per well range inside the core.

And could you talk a little bit about what's going in terms of the fracting procedure and the current state-of-the-art improvements in recovery?

Well, I think all -- the whole industry is doing different techniques and looking for -- you know, looking for that little tweaks, so to speak, that will definitely help you recover more reserves. I think right now everybody is -- you know, typically doing light sand fracts with a slight twist. Some people are pumping at a little higher rate. Some people are pumping more water, which is a little more expensive to sit there and get a little more sand in the grind to get slightly higher rates and slightly higher reserves. And then at the same time we're looking at proprietary company products that some of our service companies provide to try to increase conductivity, try to get a little more sand than what we have done before, with light sand fracts. So I think there are a number of issues. Some people experimenting with the way you set 5-plugs. How many stages you pump. So those are -- all those things are going on right now and I think everybody has a pretty good idea of what all the other companies are doing, and hopefully we'll all learn together.

Okay. Last question, second quarter gas production in the U.S. was down a tad. Can we get some sort of sense of maybe by area or kind of the ebb and flow of what's happening there, and kind of your view going into the remainder of the year, the exit rate for the year?

Van this is Vince. If you look at our overall production profile, the U.S. gas is down a little. We're seeing a fair amount of growth in Canada. Our North American gas production base is very stable, and will remain that way. Our outlook is to be able to hold it essentially flat or grow it going forward.

Okay. Thanks.

Our next question comes from Paul Tise with Lehman Brothers.

Good morning. Just a handful of questions. First on the cash side. The plan is to continue building your cash balances to 1.6 billion, and then at that point, you would be revisiting how you use your free cash flow going forward in?

Yes.

There's no -- okay. And you think it will probably be there by the end of this quarter?

Yes, before the end of the quarter.

Before the end of the quarter. Okay. On the production side, if you assume that in the third quarter you're at the low-end of the range, that would imply that the fourth quarter would need to come in north of your first quarter, if I'm doing the math right, kind of a 64 to 66 million BOE total production range. What would be driving that increase at the back-end of the year?

We've got a couple of things that are going to drive fourth quarter growth. One is a full-quarter of Red Hawk, which was, as we mentioned came on at 60 million a day net to our interest. That will produce a full quarter in the fourth quarter. That's a significant slug of production. We also expect to bring the Magnolia project, that's the Conoco operated deepwater oil project in the Gulf of Mexico on during the fourth quarter, and will contribute to fourth quarter volumes. So that's why all along we thought 2004 would be saddle shaped in terms of the production curve, and we still have a lot of confidence in that profile.

Any fuel for what 2005 production guidance might be?

We have not provided '05 production guidance, but we are going to hold as you are probably aware the analysts meeting at September and we expect to layout our expectations for not just production but for a number of performance areas are at that meeting.

Okay. Can you give us a status update on where your conversations with the agencies stand right now?

We have a -- this is Brian Jennings. We have a very active dialogue with [Moody's S&PN Pitch] and I'm sure they're listening in to the call today. We continue to talk them about our rating. We certainly believe that the credit profile the Company has improved and will continue to improve as it has in 2003, 2004, and will continue in 2005.

And you feel that whether Moody's is going to resolve their negative outlook one way or the other?

I can't comment on the actions Moody's may or may not take.

Last question. Can you give me your view on the M&A market right now in terms of where things are trading and if your view has changed around that in the last quarter or so?

No, this is Larry. Our view has not changed on that. As we said all year long, we do M&A to accomplish specific needs, not just to do M&A for the sake of doing M&A. And as we look at both our production portfolio and our exploration portfolio, we're pretty happy with where it is right now. So we don't see any glaring holes that we need to fill through M&A activities. We also see high oil and gas prices. We prefer to buy things like we did in the fourth quarter of '01, when commodity prices were in the tank, rather than where they are now. And while we will continue to monitor that situation from time to time, we remain convinced that at the moment, better use of our cash will be pay buying back our own shares. And that has been our view all year, and we see nothing today that changes that. If you compare the multiples that some of our peers have paid for companies this year versus what we paid in past years we got much the better deal. So we remain focused on buying our own shares back.

Okay. Great. Thanks.

Once again if you have a question, simply press star, 1 on your telephone touch pad. Our next question comes from Jong Bock with the Vanguard Group.

Hello, gentleman. Following up on some of the questions asked. I was wondering if you follow -- if you can pinpoint any debt to proof develop reserves targets coming up

Could you -- we didn't understand the question. Could you say it again in.

I was wondering if you follow your debt to proof developed reserves metric, and if you can provide any guidance on that figure?

Was the question about debt adjusted?

Debt to proved --

Total debt to prove.

Yeah, total debt to prove --

or net debt, whatever.

We certainly follow that. We know that the rating agencies follow that metric. And of course, you know, we took steps in 2003 to actually reduce the -- you know, our [proved undeveloped] component as percentage of total reserves, we took that down into the low 20% of total reserves. It's a metric we look at. We look at all metrics when we assess what our total debt targets are.

And I guess just a follow-up on that. For the 1.6 billion dollars that you targeted in excess of that you said you might consider a share buyback or dividend. Would you allocate an X amount above a certain number for further debt reduction?

Let me -- I want to follow up on your last question about debt per barrel. You know, please recognize that if you use that metric, you need to adjust for the fact that we have a mid-stream and marketing business, which we just gave guidance today that will generate operating margins of almost $300 million, and that value of that business would not be reflected in a simple debt per barrel metric. With regards to a --

And you ought to add that that is -- that business is substantially larger pro rata than most if not all of our peers. So it's a meaningful business for us. You can't just say, well, everyone else has a mid-stream business. They do, but not nearly as big as ours.

Right. And with regards to getting into a formula for repurchase, we have, of course, discussed what we may do with cash flows in excess of our capital budget of every payment requirements, Larry mentioned today potentially looking at the dividend or share repurchase. I don't expect us to get into a formula, but we'll certainly be I talking more about that in September.

Okay. Fair enough. Thank you very much.

Our next question comes from Ray Deacon with Harris Nesbitt.

Yeah, hi. John, I had a question about Canada. Looked like your volumes were up about almost 6% sequentially. What were the drivers there? Was that the foothills, or could you just go through the growth there?

Yeah. You know, Ray, I don't have all of the exact details of the growth by region, but I can tell you that we're experiencing growth almost across the asset base. I mean, there are a couple of areas that while they're still very high net-back areas for us, they're not growth areas. But we're experiencing growth in even some of our more mature areas like, for example, [inaudible] Arch. And certainly the experience that we've had in the deep basin and in the foothills has been very, very positive. So we're quite pleased with the results.

Okay. And is there any update on Jack Fish there? Have you done anymore work that's going to bring you closer to moving forward on that?

We're continuing to work diligently on that. We're in the engineering stage right now. As I think you may know, we're currently awaiting our regulatory approval, and the stage that that is at, our regulatory approval should be completed just about now, in the middle of August. And if there are no interventions or interested parties that come forward, we ought to see that regulatory approval come through for us in November, it's kind of mid to late November of this year, we hope. And that's just based on the timing of other regulatory approvals for similar kinds of projects. And if there were a hearing, which could happen but we don't have an indication of that, if there were a hearing required because of interventions or other interested parties coming forward, then the approval process would probably take us into the first quarter of next year. So all in all, I would say we're right on track with what we've talked about in the past with regard to that project.

Okay. Great. And just a quick question on the gathering side. Was the increase in guidance there due to -- is it higher volumes or fees? Are you able to raise your gathering fees?

Our decision to raise guidance was driven principally by expectations of product prices. Although, much of the activity certainly in the greater Fort Worth region and the greater Barnett Shale play, may lead to higher volumes through our Bridgeport plant there. But I would characterize our performance there as being driven by product pricing.

Okay. Great. Thanks very much.

Our next question comes from Mark Meyer with Simmons and Company.

Good morning. Larry or John, I don't know if this is a question for you. Just one. Conceptually on development for St. Malo and Cascade, Larry, I think I've seen some things in the past recognizing this an official guidance or target start-up date. But potential production contribution in 2007, just wondering if you could address conceptually what is on the table as far as development options? And whether you are looking at things that may be relatively straight forward, or something more exotic given the water depths?

Well, I'll let Bill answer most of that questions. But obviously it takes awhile to get those on stream. And we really haven't on the stage yet where we have agreed upon the final production scheme. So it's kind of hard to predict exactly how much and when. Bill, you want to provide more background on the thought process there?

Yes, I would be glad to. I think that the 2007 number that you quoted is probably a little bit premature. I'd say it's more like 2008 would be a more likely year to start up lower tertiary production out there. We are currently looking at various production scenarios including the possibility of some FPSO development out there which may make the most sense. The pieces of the puzzle are still coming together, however, and I think a lot of that depends on how many discoveries are out there. We've got Cascade and St. Malo. We're evaluating Jack and Sardinia, and the whole trend, you know, that we're currently involved in is in excess of 140 miles from Cascade to Sardinia, let's say. And I think the picture is -- should be clearer after we get Sardinia down and evaluate some of these other datas that we have from the Jack well. So, you know, I think that the production scenarios range from some sort of a deepwater floating system, including FPSO development.

With 2008 being kind of early as preliminary for a date?

Yeah, I would say so.

Okay. Thanks a lot.

Our next question comes from John Gerdes with Southwest Securities.

John, or Larry, this would be for you guys. One of you two. The West African prospects you guys plan on drilling later this year. Just a little more specificity on the specific prospects in each of those areas. And I understand, I guess you have 95% still in block-OPL256, still planning to sell that down?

Yes. And let me refer that to Earl Reynolds who handles our international.

Thanks.

Hey, John, basically for the rest of this year, our our focus will be in Equatorial Guinea and Block-P and that is a -- kind will look like to what Enron has us been doing. With kind of a stratographic trap a [gratacious] type opportunity. Relatively shallow water opportunity, so if we're successful we can get it on to production relatively quick. About a 200 million barrel opportunity in terms of potential. Outside of that, really our drilling program in West Africa is primarily driven because of associated with the rig activity -- rig opportunities pushed to the latter part of the year, block-10 in particular in Angola is latter part of the year, maybe even early in '05, as well as block-256 in Nigeria is probably a late '04, probably early '05 drill. In terms of our equity, you're exactly right, John, we have 95% equity in block-256, and we are currently in the format process for that block.

Okay. That's all helpful. Just one follow-up. The Brazilian well, the BMC-8 the status of that well, please?

Okay. John we've got that well [TDed,] and we're currently in the evaluation stage with that as we speak, so.

That's about an AFE, what about 10 million, Earl?

That's correct.

Great. Thank you for that.

Okay. We've got time for one more question at this point.

All right. Our final question comes from Alexandra Sotelle with Knott Partners.

Thank you. A few very quick questions. Can you remind me first of all how many noncore locations you expect to have drilled by the end of this year at the Barnett?

Go ahead and run off your questions and we'll be working on the answers.

Okay. The second one, and you might have addressed this before, but I just don't remember. But with your Barnett production being down sequentially and I guess taking into account what you're drilling plans are for the next whatever, couple of years. What do you roughly think the profile -- the production profile should look like?

Okay. Let me answer the first one. In the noncore area, originally we said we would drill about 52 horizontal wells, and so far the year, it looks like we have spudded 27 wells, 22 of them which are horizontals. If you look -- and again, we're still -- I think Vince mentioned, we're still in our budget process right now. But for next year, we're thinking depending -- again it depends a little on the capital spending, but we ought to be able hold the Barnett -- I think there's a very good chance that we will be able to hold it flat.

Alexandra, this is Vince. I'll add that our production, we're on track now for an increase in 2004 Barnett Shale production over the actual 2003, and that we think the outlook from here is pretty stable to up. And it does depend on how much capital we apply in 2005. We don't expect additional declines in 2004. When we finalize our capital budget in '05, we'll decide whether we're going to take the thing up or down.

Okay. Thank you And Nansen and Boomvang. You have mentioned that there are 2 more wells being hooked up there. I think you said in September. Can you give us a sense for magnitude, or does it matter?

Bill, you want to take that question?

I think it's -- I think the Nansen and Boomvang, it should be net to us. I'm in the vicinity of about [inaudible] barrels a day.

Okay. And can you finally remind me what the target depth for Sardinia is?

29,000 feet.

I'm sorry?

29,000 feet.

29,000. Did you talk about prospect size?

No, we haven't released that data.

Okay. Okay. Thank you.

It's similar to Jack and Cascade, similar type structure.

Right. Okay. Great. Thank you.

Thank you.

Okay. Well, as you know we always limit this to one hour, trying to be respectful of everyone's time. We appreciate your attention on this call, and we look forward to seeing many of you in September. Take care. Have a nice summer.

This concludes today's teleconference. Thanks for attending, and have a great day.