德文能源 (DVN) 2003 Q2 法說會逐字稿

Hello and welcome to the Devon Energy Corporation's second quarter 2003 results conference call. All lines will be in a listen-only mode until the formal question-and-answer session. At that time instructions will be given if you have a question. At the request of Devon Energy, this conference is being recorded for instant replay purposes.

At this time, I'd now like to turn the conference over to Mr. Vince White, Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you. Good morning, and thanks to everyone for joining us today. The purpose, of course, is to spend an hour reviewing our second quarter results. We're going to start with Larry Nichols, our Chairman and CEO. He will give you his thoughts on the quarter. Then Jim Hackett, our President and Chief Operating Officer, will provide an operations update and at that point I will return and discuss the financial results, and then as is our custom we'll open up the call to your questions.

Before I turn over the call to Larry, I have a couple of housekeeping items to cover. First, I want to remind you that when we provide forward-looking information, as we will in this call, that we run the risk that our actual results will differ from our estimates. For discussion of risk factors that could cause our actual results to differ, please see our Form 8-K that we filed with the SEC on May 8th of this year.

Second, I want to point out that we will refer to certain non-GAAP measures during the call. The new disclosure rules require that we reconcile these measures to GAAP performance measures and explain why the non-GAAP measures are useful. That information, the required disclosures, can be found in today's news release. If you did not receive a copy of that release, you can get it from our website at www.devonenergy.com. I'll turn the call over to Larry.

Thanks, Vince. For Devon, the second quarter was one of an exciting whirlwind of activity, one punctuated by terrific results. Oil, gas, and NGF production came in at the high end of our forecast at 56 million equivalent barrels. Commodity prices were, of course, robust. NYMEX wti averaged around $29 a barrel, and Henry Hub Gas around 540 in ncf.

With both production and prices strong, Devon's financial performance set records. For the second quarter, production revenue and earnings all climbed to the highest level in Devon's history. We earned $356 million, or $1.62 per fully diluted shares. Second quarter cash flow, before balance sheet changes, totaled $890 million.

Devon's financial strength also continued to prove during the second quarter. We ended the quarter with 724 million of cash in the bank, and a net debt to total cap ratio of about 47%. Net debt to total cap was more than 60% just one year ago. We expect this measure to improve further during the remainder of this year.

During the second quarter, we paid off Ocean's bank revolver that had a balance of 210 million. We bought another 118 million of Ocean notes through a tender offer. In July, after the second quarter, we called another $200 million of 8 and 3/8 notes. Also in July, we trimmed 6 million in annual interest costs but issuing 500 million of three-year senior notes in conjunction with a 500 million interest rate swap. We'll use the proceeds to repay 500 million of higher cost term loan. As a result, we're lowering the interest rate on that $500 million of floating rate debt to LIBOR minus 27 basis points.

With gas prices between $4 and $5 per Mcf, and with North America's gas supply only sluggishly responding to higher drilling levels, the economies of Devon's drilling program are robust. We expect our exploration and development capital expenditures to come in near the high end of our 2 to $2. billion forecast range. We are confident that we will meet our 2003 organic production growth target of 4 to 6%. This was the target that was set for ourselves at our December meeting last year. So, we continue to deliver on our commitment to both repay debt and to fund a vigorous capital investment program that will grow production this year.

The second quarter was a very active period in the field. Exploration and development capital expenditures totaled $544 million for the second quarter, $979 million for the first six months. Our exploitation and development projects that drive our 003 production growth are on-target. Now, the Barnett Shale, our large field in north Texas, is providing Devon with well over 500 million cubic feet per day of gas equivalent production, and that production continues to climb as our horizontal wells continue to be successful. Our other developmental project in Equatorial Guinea and China and Canada, the deepwater gulf are still moving ahead as planned.

The pace of our exploration efforts accelerated in second quarter. Although, a majority of our activity is planned for the second half of the year, results to date have been mixed. Several high-profile wild cats drilled in the first half have been dry. It's not to be unexpected in a high-potential exploration program. But, we also had some pretty encouraging results from several of our other exploratory wells. The results were the majority of our high-profile wells we're drilling this year will come in in the second half.

In addition to normal business, we have been very active integrating the Ocean and Devon operations. On April 25th, as everyone knows, both company shareholders overwhelmingly approved the merger, and we immediately began our integration of the two companies with a goal of having all of the people, all of the organizational decisions made by June 30. We met that goal. 80 employees are relocating from Houston to Oklahoma City. We relocated the Lafayette Louisiana production group to Houston, both Ocean and Devon had field operations in Lafayette. Those operations remaining Lafayette and have been consolidated into one office.

Also during the second quarter, we announced the closing of our offices in Woodlands, a suburb in Houston. These employees have been reassigned to either Oklahoma City or downtown Houston, depending upon their functional areas. So, the consolidation of all of our Houston operations into one downtown office in Allen Center is essentially complete. In total, we hired 549 former Ocean employees. These include 54 geologists and geophyicist, 50 engineers, seven land professionals, and 45 technical support staff. A total of 291 former Ocean employees and 247 former Devon employees are being released.

Following this integration, Devon is positioned to reap the benefits of our premier portfolio of North American natural gas assets coupled with our exciting worldwide exploration capabilities. After these relocation and transitions are finished we fully begin to start realizing the $50 million in annual cost savings that we said we would expect from this merger.

Before I turn the call over to Jim Hackett, I want to remind you that Devon will host its annual executive briefing for analysts and institutional investors in New York on Tuesday, September 9th. The last few years we've been holding this annual briefing in December, so we want everyone to make sure you're aware we're moving it up. If you have not received an invitation, let us know.

At this point I'll turn the call over to Jim Hackett.

Thanks, Larry. As Larry indicated we had an active second quarter with the drill bit with 88 rigs running company wide, two-thirds of which were operated by Devon. During the quarter we drilled 329 wells of which 311 were low-risk development or exploitation wells. The other 18 were classified as exploratory and 14 of those wells, including 12 in Canada, were successful. Of the 329 wells drilled during the quarter, 243 wells were in the U.S. onshore area. In the Barnett Shale in north Texas we split a total of 94 wells in which 15 were horizontals. All of the second quarter Barnett Wells were successful.

We exited the second quarter producing just over 530 million cubic feet equivalent per day. This is up about 5% over first quarter exit rates in our competence in the viability of horizontal drilling in the Barnett continues with each successive quarter of results. We now have 22 horizontal Wells on production, producing for almost half a year and currently producing 34 million cubic feet a day in aggregate. We expect to drill up to 70 horizontal wells in the Barnett by end of the year, up from the 50 wells we projected in last quarter.

To give you a sample of other specific successes on shore, in the Indian Basin field in southeast New Mexico, we completed six wells in the quarter, adding over 2,000 barrels of production as part of a larger year to date effort of 10 wells and an additional five wells through year end. In east Texas, we continue the six-rig drilling program in an active recompletion program as well, drilling 18 new wells and recompleting 30, resulting in a net up-lift of 42 million cubic feet equivalent per day. These programs reflect a large inventory that will keep us active for the foreseeable future.

On shore in the Texas Gulf Coast and Webb County are %100 [INAUDIBLE] #8 exploration well logged about 75 feet of net pay in WILCOX, which looks to set up several additional locations. In Canada, you remember, we had a very active first quarter with our winter drilling program, enjoying activity, typically, slows dramatically in the second quarter. This year saw a couple of exceptionally wet spring, made many areas inaccessible due to muddy roads, which delayed field access until late in the quarter. None the less, by the end of the second quarter we had 19 rigs running in Canada and expect to have as many as 24 rigs running during the third quarter. During the second quarter we drilled 60 wells in Canada, 20% of which were exploration wells.

In the Canadian foothills, completion of the Grizzly pipeline extension allowed to us tie in two additional Grizzly Valley wells, placing them on stream at a combined net rate of over 7 million cubic feet per day, bringing Devon's net production in the Grizzly Valley area to about 30 million cubic feet per day. With the pipeline extension complete, we expect our production to continue climbing as we bring out additional volumes from previous discoveries in this area. Our net production now out of the foothills tops 130 million cubic feet per day.

You've probably heard or read about the Alberta Energy and Utilities Board's recent ruling to shut in gas production, located above the Bitumen Oil Sands. Fortunately, the impact of this shut in the Devon is minimal. As a result of this ruling, Devon will shut in only about 5 million cubic feet a day of gas early this fall.

Off-shore on the Gulf of Mexico shelf, we completed five wells during the quarter, and as mentioned in our first quarter call, we made a discovery in our Grays Prospect on Galveston Block 424 in April. This Devon-operate discovery well, encountered more than 100 feet of net pay in multiple sands and was tested in June at a restricted gross rate of 15 million cubic feet per day. The well is expected to practices 20 to 25 million a day gross when on line. Two off set wells are planned for later this year with production from all three wells expected in the first quarter of 004 at a rate of 30 to 40 million a day net to our interest.

We had two other notable exploratory successes on the shelf during the quarter. First, the 2 #20 with term prospect in Eugene Island 126 was drilled and completed and attained a rate of 8 million a day of gas and 2100 barrels of condensate. Devon is the operator with 100% working interest in this well.

The second well, the [Laumbardee] 82 on Vermilion Block 196, was brought on line in mid June, is currently producing 5 million a day of gas and 700 barrels of condensate to Devon's 25% working interest. Another Lombardi Well, B A-3 has been complete and tested at a choke-restricted rate of 3 million a day of gas and 140 barrels a day of condensate, again, net to our interest.

In the deepwater Gulf of Mexico, on the development front, completion activities continue at the Nancen Boom [Bang] complex. The Nancen [E-8] well was complete and brought on line along with the last of the Nancen project completions, the A-9. Total gross production from this field and these facilities is currently running 33,000 barrels of oil and over 193 million a day of gas, or 30,000 barrels equivalent per day net to Devon's interest. At Boomvang we will be drilling another development well in the third quarter. We averaged 39,000 equivalent barrels per day net to our interest during the second quarter from both the Nancen and Boomvang fields. Our Zafiro Mississippi Canyon Block 496 was brought on line ahead of schedule in late June and we've had some typical start-up problems. The well is, currently, off-line to repair a damaged choke mechanism and clean out flow lines. The [Zia] was producing at a gross rate of over 7,000 barrels a day of oil equivalent and climbing before the choke problem. We should have the well back on line next week and expect production to climb to over 8,000 barrels of oil equivalent per day in this operated 65% working interest field.

Our Cellspar development at Red Hawk, continues to move along on schedule with first production estimated in Q3, 2004 at 50 to 70 million cubic feet equivalent per day net to Devon. We have started testing the first completion and results are encouraging relative to our estimates for field production. At Magnolia, we completed and tested the fourth development well and are running intermediate casing on the fifth well. Test results on that fourth well at 7,000 barrels a day support field production estimates. Construction of the tension light platform is continuing and we expect first production late in 2004, with a peak net rate of 9 to 12,000 barrels a day, equivalent expected in 2005. On the Santa Rosa prospect, located in Atwater Valley, we drilled a dry hole with Devon's 1/3 interest, costing $5 million.

In our deepwater exploration program we have six wells currently drilling and expect to participate in another four wells by year end. During the second quarter, we experienced limited drilling days in two busted anchors at Yorktown, because of strong [luke]currents and [eddie] pools in the area. However, we were able to drill over 1,000 feat and now are at about 23,000 feet total depth. Currents have kicked up again and we are waiting to drill ahead after testing Blps two days ago. Gross dry hole costs are now estimated at $76 million, with Devon's share at $56 million. We will probably be drilling here for another two to three weeks, which I know is a familiar story to all of you, but still our best estimate of the remaining time to test the objective stands, once the currents subside.

The Sturgis Prospect and Atwater Valley 182 is the second of our four well deepwater joint venture commitment with Chevron Texaco, which will earn us an interest in 71 deepwater blocks. [Sturgis] is a 26,500-foot subsalt test in 3600 feet of water and is currently being side tracked for further evaluation. Devon has a 25% working interest in this prospect.

In our joint venture with Kerr McGee drilling continues on the Shiner Deep Prospect, located in Garden Bank 700, we expect to be at T D later this month.

Other deepwater high-impact exploratory wells we have drilling are; Yorick and Green Canyon, where we have a 35% working interest, St.Malo and Walker Ridge at %22 working interest and Saratoga in Green Canyon with a 50% working interest. Devon's net reserve exposure from our six deepwater exploratory wells is over 300 million barrels of oil equivalent. The Tuscany Well and De' Soto Canyon, with a 6% working interest, will follow Saratoga using the same rig.

Turning to international operations. We had eight rigs running at the end of second quarter and during the quarter drilled a total of 14 international wells. Looking first to our activity in west Africa, reported last week that we had increased production from the Zafiro Field offshore Equatorial Guinea. The new [FPSO] Serpentina was put on production in the southern expansion area on July 13th, 50 days ahead of our September 1 target. Serpentina is the third producing field in Zafiro and increases gross field capacity to 300,000 barrels of oil per day.

Production ramp-up is proceeding ahead of schedule in the southern expansion area where we are producing 80,000 barrels a day gross from 7 wells. We expect to have a total of 14 wells producing next year from this area. We will have a three-rig program underway in the field in 2004 and current net production field wide is about 53,000 barrels per day. Off-shore Ghana; the exploratory project was unsuccessful at a net dry hole cost of $9.9 million. We're evaluating the next potential target in this area.

In China despite the impact of typhoon season, platform and topside installations are completed Panyu 5-1 and near completion in Panyu 5-2 while installation hook-ups and conditioning tests are underway.t The FPSO Vessel is going through final system checks and conditioning activities and should stay from Shanghai in mid August. We expect to see first oil sales in the fourth quarter with peak rates in mid '04 of 15,000 barrels a day oil equivalent net to Devon's interest.

In Egypt the C platform at East Side has been completed and the C-1 Development Well is drilling ahead. We should see initial production here in September.

Finally Devon's marketing and mid stream is turned in another terrific quarter with its operating margin exceeding $58 million. Gas pipe line throughput averaged almost 1.5 Bcf a day in the quarter. In north Texas we hooked up 97 wells, 18 third-part Devon wells and 18 third-party wells as installing 29 mild new pipeline. Also the marketing mid stream group is consolidated its operations in Oklahoma City, reducing overhead and improving efficiencies.

Now I'll turn the call over to Vince for the financial review.

Thanks, Jim. First I want to remind everybody that we closed the merger with Ocean on April 25th, so our second quarter reported results include only about two-thirds of Ocean's second quarter production of revenues and expenses. We've also provided you with pro forma financials in the press release today, so that you can see how the quarter would have stacked up had the Devon and Ocean merger been completed for the full quarter.

Looking first at production, company-wide reported production of oil, gas, and natural gas liquids was 56 million barrels in the second quarter of '03. The guidance that we provided during the first-quarter conference call was for second-quarter production to fall between 55 and 56 million barrels equivalent. Second quarter production represents a 13% increase over the seconds quarter of 2002. Included in the comparative quarter, that is the second quarter of 2002, is 4.9 million barrels that Devon produced from properties that were sold later in 2002.

Looking at the sequential quarter comparison, Devon's first quarter 2003 production totaled 44.3 million barrels, so on a sequential quarter basis, second quarter production was up about 11.7 million barrels, or 26%. For both the year-over-year and the sequential quarter comparisons the Ocean merger was the big driver for production growth. For a sequential quarter combined company comparison, you must add the 3.9 million equivalent barrels that Ocean produced in the second quarter prior to the merger. That yields pro forma second quarter production of 59.8 million barrels, and that's essentially flat with first quarter pro forma production of 59.2 million barrels equivalent. These numbers are consistent with the guidance that we provided during the first quarter conference call.

Looking ahead, we expect production volumes to ramp up in the third and fourth quarters. The various development project that Jim discussed will contribute the volume that will increase our production in the second half of the year and we are affirming our previous guidance for third quarter production. We continue to expect third quarter production to total between 61 and 63 million barrels of oil equivalent. That will give us full-year reported production of between 224 and 229 million barrels of oil equivalent.

Moving now to oil and gas prices and although prices were down from first quarter levels, they remain very strong in the second quarter. Our floating price realizations, that is the prices realized on our unhedged volumes, improved relative to index prices. I'll cover just a couple of those. U.S. floating gas price realizations, averaged $5.05 per Mcf in the second quarter. That's just 35 cents less than NYMEX Henry Hub. Our Canadian floating gas price realizations, averaged 497 during second quarter, for 43 cents under the Henry Hub NYMEX index.

Our U.S. and Canadian floating oil price realizations also improved relative to NYMEX during the second quarter. The U.S. floating world class realizations averaged 28.14, that's 82 cents less than NYMEX and in Canada, our second quarter floating world class realizations averaged 24.64, or $4.32 under NYMEX.

Before we move to expenses, I want to point out the contribution of our marketing and mid-stream operations. Second quarter marketing and mid stream revenues were 335 million. When you back out the associated operating expenses, you'll find that we had second quarter marketing and mid stream margins of $58 million. That's about $7 million better than our expectation, due largely to higher NGL prices, but this is about the third or fourth quarter in a row that our marketing and mid-stream division has out-performed our guidance. We now expect the marketing and mid stream division to generate more than $230 million of margin in 2003 and based upon the cash flow multiples at which mid stream assets typically trade, we've been told by more than a few investment banks that our mid stream business would be valued on a stand-alone basis at about $2 billion. When people are looking at our per-barrel measures of expenses and indebtedness they often overlook the fact that we have such a significant mid-stream business.

Moving to expenses, most items were in line with our guidance. I'm going to cover just a few items that varied from our expectations where that had unusual or nonrecurring components. The first one I want to touch on is lease operating and transportation expenses. In aggregate those totaled $274 million in the second quarter. That works out to $4.89 per barrel equivalent. That compares to the midpoint of our full-year guidance of $4.52 a barrel. The biggest drivers were higher than expected well workover expenses, higher than expected fuel and electricity costs, and the adverse effect on LOE of the strengthening Canadian dollar relative to U.S. dollar.

Moving now to general and administrative expenses, we reported 93 million during the second quarter. That was well above our forecast of between 72 and 73 million. The difference from the forecast is attributable to three items that are mostly one-time in nature, and the fact that they were there in the second quarter, really doesn't impact our outlook for future G&A expense. First of all, we took an $8 million charge for closing our Woodlands office, which Jim mentioned, Jim and Larry both mentioned, was closed during the second quarter. Another $8 million of expense was attributable to a noncash increase in the deferred compensation expense. This was offset by a $7 million related increase in other revenue. That expense entry results from changes in benefit plan investment asset values. Generally accepted accounting principles require us to report the changes in this portfolio, both as an increase in income and an increase in G&A expense.

The final item that took G&A expense over budget results from bonus units that are held by certain former Mitchell employees. These are essential phantom stock, and because Devon's stock price increased during the quarter, we recognized 4 million of G&A expense related to those units. When you cut all the way through it we still expect our third and fourth quarter G&A to come in consistent with our previous guidance of 82 to $83 million a quarter. As we move into 2004 we expect to see downward pressure on G&A as we start to realize additional synergies from the Ocean merger.

Just a quick comment on the impact of foreign currency exchange rates on Devon's operations. I mentioned that it caused LOE to be higher. The fact that the functional currency of our Canadian sub was the Canadian dollar results in the Canadian dollar strengthens, it impacts various expense categories as expressed in U.S. dollars. However, the overall earnings impact for the quarter was very modest at about $13 million, or 6 cents per diluted share.

Before we move to income taxes, I want to offer a couple of observations about Devon's cost structure and break-even commodity prices. In the second quarter our pre-tax expenses, excluding the revenues and expenses from our mid stream business, totaled $2.83 per Mcf equivalent.

So, our E and P business, without the benefit of our mid-stream earnings, had an implied second quarter pre-tax break-even of about 2.83 per Mcf. However, as Jim mentioned, our mid-stream business generated positive margin of about $58 million during the quarter. When you take that into account, it reduces our second quarter pre-tax break-even price to $2.66 per Mcf. There were some unusual expenses such as merger costs in the second quarter. So, the break-even on an ongoing basis would probably be even lower.

On a cash expense basis, Devon's break-even prices are considerably lower than on an earnings basis. If you look at the second quarter, our pre-tax cash expenses, before taking into account the revenues and expenses from the mid-stream business, totaled $1.60 per Mcf equivalent. When you back out the benefit of a mid-stream cash margin that lowers it to $1.43 per Mcf equivalent.

These analyses probably overstate our break-even prices, because if commodity prices were to drop appreciably, many of our expenses, such as production taxes, fuel costs, and so on would decline as well. In any case, Devon's margins continue to be very competitive with our peers.

The last expense item I want to cover is income taxes. In the second quarter they totaled 233 million. That's about 39% of pre-tax earnings. That is higher than our guidance, and that's due, primarily, to higher than expected pre-tax earnings. As our pre-tax earnings increased, the effective tax rate on our pre-tax earnings increases as well. That's because the positive effect of certain of the tax advantage transactions that we've done in the past, diminishes relative to overall taxable income as taxable income goes up. We expect our full-year 2003 total income tax expense to be consistent with our previous guidance, between 25 and 45% of pre-tax earnings with between 5 and 15% of that current and 20 to 30% deferred.

When you take all the revenues, back out the expenses, you'll find that we had reported second quarter earnings of 356 million, or $1.62 per share. This earnings per share number includes some items that are typically excluded by the sell-side securities analysts in their published estimates. In aggregate, those items increase second quarter earnings by about 6 cents per diluted share. After we adjust for that, we had earnings of $1.56 per diluted share, or 4 cents over the first call consensus. That level of earnings translates to cash flow before balance sheet changes of about 890 million, and while reg G prohibits me from providing you cash flow on a per share base, I can remind you that our diluted common shares outstanding, during the quarter, averaged 221 million.

For those of you that keep track of capitalized costs in your model, we capitalized 38 million of G&A and 12 million of interest expense during the second quarter and we expect those items to run at about this level in the third and fourth quarters of this year.

That ends my prepared remarks. We'll open up the call to your questions at this point.

Thank you. At this time we will begin our question-and-answer session using our polling feature. If you after question or a comment you may press star 1 on your telephone touch pad, and should you need to cancel you may press star 2. If you are using speaker equipment, you may need to pick up your handset prior to pressing star 1. Once again, if you have a question or comment, please press star 1 and star 2 should you need to can sell. One moment while the questions register.

Our first question comes from Mark Meyer from Simmons.

Good morning, this is Brian in for Mark. I wondered if you could go through the numbers on the head count, what the Ocean integration again. Missed a couple of those. Hello?

Mark, we couldn't hear the question. Could you repeat it, please?

This is Ryan in for Mark. Wondered if you could go through the Ocean integration numbers on head count again. I missed a couple of those. Hello?

Are you on a speakerphone?

I've picked up.

Okay. And you've asked for ocean integration -- I'm sorry, you were cutting out.

Okay. Looking for Ocean integration numbers as you related them on the head count.

Yeah. Apparently we've got a problem with the connection. Let's just move to the next question. We'll try to attempt to answer your question later. I'm sorry.

Thank you and our next question comes from Phil Pace from Credit Suisse First Boston.

Hey, Vince, can you hear me?

We can hear you great, Phil.

I was just curious, you went over the horizontal work in the Barnett pretty quickly. How many wells were on line and how are they performing, and how many of those represent data points outside of the core area, and what does that tell you in terms of proofing up some of the acreage out of the core area?

Phil, this is Brad Foster. We currently have 22 billions on line, of which they're making 34 million, which I think Jim told you. Of those, 18, well, 17 of those are in the core. We have six outside the core. Five of those wells are making about 6 to 7 million a day, and then we have one well down in Johnson County that's been restrict due to flow line conditions. So, I mean, right now, it's early, but we're encouraged by what we're getting outside the core, and it's just going to take us a little bit more time. Right now, we have 29 wells that we've drilled so far, and we have 14 wells that are in various stages of hook-up and five of those wells are outside the core, so hopefully next quarter we will have better information for you and a little bit more history to give you and let you know where we're at.

Thanks, Brad.

Thank you and our next question comes from Ellen Hannan with Bear Stearns.

Good morning. I wondered if you could give us a breakdown for this quarter where your international oil production by area.

This is Earl Reynolds in Houston. Currently, we're practicing around 35 to 40,000 barrels a day in Zafiro as Equatorial Guinea. Producing around 5,000 barrels a day,I'm giving you net interest, in Egypt. We're producing about, just under 5,000 barrels a day in Coted'izoire west Africa. Then we're producing just around 5,000 barrels a day in Russia. Then the last point would be in [Gabon], where we're producing just around 5,000 barrels a day in [Gabon]. As you know, we are a carried interest in Azerbaijan, about 5,000 barrels a day in the ACG project.

If memory holds correct, I think that the Ocean's production in Egypt was running around 9,000 barrels a day. Has something change there?

Actually, I gave you the number for the operated project. The total production is around 8,000 barrels a day in Egypt, including our non-operated production. I gave you numbers for the quarter. Obviously, with our Equatorial Guinea production coming on line in the beginning of this quarter, we've ramped that up, now our production, Equatrioal Guinea, increased from the 35 to 40,000 barrels a day number to approximately 53,000 barrels a day.

Do you expect to hold that 53,000, or when do you expect that to --

We've got several wells to put on line, and the SEA. We've got five more the rest of this year, as Jim mentioned, and we have a couple more wells, practicing wells, in 2004, and in addition to some injectors that will be trailing, but we expect that to increase a little above the 53,000 barrels a day net. We should be getting close to our peak capacity here in the near term in the next few months. We expect them to remain flat for 2004.

Ellen, this is Mike Lacey. Just to kind of add a little color to that, we and Exxon have been so excited by what we've seen in the initial wells we've put on production that studies are underway to find ways to de-bottleneck the Serpentina facility, so we can, hopefully, increase production over the capacity limits we'll have out there

What is the capacity limit?

110,000 is what it's designed for.

That's gross.

The whole capacity for the field is around 300,000 barrels a day, when you add all three facilities.

Thank you very much.

Before we take the next question, it's been passed on to us that the first caller wanted us to review the head count reduction numbers that Larry gave in his portion of the presentation. Those numbers are 291 former Ocean employees are being released, and 247 former Devon employees are being released. Some of those have already been released, some of those are working with us on a transitional basis. Those numbers will be achieved by year end.

Okay, Brian's line is now polled up, and, sir, did you have any additional questions at this time?

Yeah. It's Mark Meyer. I'm sorry, earlier difficulties. Just following on that, Vince, what was the pre merger Devon base that that 247 will come out of?

Company-wide employees, Devon, prior to the merger, was over 2,000.

3000, 200, 3500

Then I just add the Ocean 549 to the 291 and get the pre-Ocean?

It was actually more than that, because it doesn't include some of the field international employees.

We can get back to you and give you exact numbers.

Quick follow-up from you, Jim, on Zia. Heard from your partner last weak about low probably that there might be a down-hole problem. Are you saying by your comments today that you confirm that there's no problem with the frac packs?

No, we think was an issue of, basically ,the well cleaning itself out at this point, and that's why we're doing the work we mentioned. We don't have any reason to believe it's something else.

Okay. One cleanup question for you Vince. How much of the 37 cents relative -- 37 cents a barrel relative to your midpoint on LOE was attributable to the weaker U.S. dollar?

I've got that data. Foreign exchange impacted second quarter LOE about 7.2 million dollars, or 13 cents a barrel.

Thank you. That's all I had.

Thank you, and our next question comes from John Herrlin from Merrill Lynch.

Yeah, couple of quick ones. You didn't mention anything about any of your coal bed operation. Can you talk about Powder River, [Cherokee], San Juan?

Don DeCarlo, do you want to address the Powder river?

Yeah, this is Don DeCarlo. Can you guys hear me okay?

Yeah.

As far as our activity at Powder River Basin, we're currently running just one or two drilling rigs. As I think you're all aware, the record of decision on the IS was released. The BLM has begun to slowly issue permits. We've begun to actually see a few permits coming in for some of the Powder River drainage. Devon has'nt seen any yet, but it's imminent. We expect in the next period of the next few weeks that we'll get some permits for our deep [INAUDIBLE] project that's working very well at Juniper Draw. We think it's going to be slow and steady and expect to drill another 50, or so, wells in the second half of the year.

Of course, in the San Juan Basin, we've now received regulatory approval for down spacing throughout the coal bed play from the current 320 spacing down to 160's. That is going to allow us to drill substantial amount of in-field coal wells. We've drilled six year to date, completed four of those, and have outstanding test rates on three of the four in excess of million and a half to two million a day. One well is actually doing 3 million. We anticipate probably drilling 15, or so coal wells this year, then another, between 30 and 40 coal wells, in 2004 on our two project in the San Juan Basin.

Nothing on the Cherokee? Same?

Cherokee, we've currently got one drilling rig running. We're currently producing about 20 million gross, 15 million net there, have recently brought on some pretty nice wells, couple hundred Mcf a day, each down in the Lenapah area. Expect to keep that rig running, probably, through the remainder of the year. In aggregate this year I would expect we'll drill in the range of 50 or 60 wells out there. Currently, in the middle of a very detailed technical analysis trying to high grade the areas, looking for the best place to move next for the best economic opportunities we see in the play.

Okay. One other one from me. Larry, you said initially that your drilling results were mixed. They really didn't sound it, given the kind of plays you're pursuing, but on a going forward basis, are you going to change your balance on the wildcatting side on international versus domestic, et cetera? Can you give us any sense?

Well, as the statistics that Jim gave you showed, the bulk of the drilling we're doing in the deepwaters occurs in the second half. So, based on the few wells we drilled in the first half, not enough there to draw any conclusions. So, we certainly don't plan any changes in anything we're doing at the moment.

Okay, and lastly from me, Barnett, how active do you think you can remain in the play as you expand beyond your core area?

Well, obviously, we're still continuing to grow that as we, you know, as you heard, we've increased the number of horizontal wells we plan for this year from, I think it was seven we announced at the beginning of the year, up to 50 at the end of the first quarter and we've now ramped that up to 70. You know, how long that will last, how many years out there, is difficult to say at this time, until we have the result from these wells and see how far we can take this, but, obviously we have a lot of development left to do out there in the future.

Thank you.

Thank you. Our next question comes from Irene Haas from Sanders Morris Harris.

Thank you. My question has to do with, actually for both Larry and Jim, now that you have the two organizations together for three or four months now and I just kind of wanted to see what you can tell in terms of just incremental opportunities you can see in terms of cost savings. One comment, Jim said earlier, that there could be more synergy to be realized in 2004. Can you just sort of outline areas where you can either improve efficiency or cut cost or both?

Well, we've already addressed the employee savings, and that was in line with what our plans were when we designed this merger to begin with. You know, the types of savings that one can achieve in these type transactions are just legant. It ranges from, you know, increasing your bargaining power and your ability to buy insurance at a cheaper rate to bye all the goods and supplies at cheaper rates, because you have a bigger bargaining power to achieve those economies. You know, organizing helicopter schedules so that they can hook up more, you know, get more people to more fields more efficiently, you go on and on. Nothing heroic in one individual item. It's just that every single item that you spend, and when you after two-plus billion dollar budget, there's a lot of money being spend there, and every one of those line items you can save money on by combining the bargaining power of the two companies, which is greater than either company standing alone and we've seen that happen in every acquisition we've done in the past.

Okay. Maybe, can you give me a little more color on, you know, you said the second half is most of your deepwater wells to be drilled. Can you name a few key ones and roughly the timing and predrill estimate?

I think, Irene, we covered some of the bigger ones in terms of the absolute size, but you know, we have [Tuscany] coming up. We've, obviously, got York Town still drilling, which is a big well for us, St. Malo and others are lined up as well, so I think, then there will be another Chevron Texaco joint venture well, another Kerr Mcgee joint venture well, likely, as well as some additional drilling around Nancen Boomvang. So, I think, the ones that are big, probably, went through, plus a few extra, for the last of the year and we've got six drilling right now, four to go.

Thanks.

Irene, for pre drills and that kind of thing, if you want to call us later today, we've got all that information. We just don't want to drag everybody through all that detail.

Thank you. Our next question comes from David Khani from Friedman Billings & Ramsey.

Yeah, hi, guys. You've been pretty active paying down some of the Ocean debt and refinancing. How much more do you think you have left to do this year?

This year, Brian, why don't you take that.

Sure. David, it's Brian Jennings. We, obviously, have called all the callable debt we have at this point. We will continue and expect to continue, subject to commodity prices through year end, to build up the cash balance, and, of course the magnitude of our year-end cash position will be driven, obviously, by commodity prices through year end, both oil and gas, and our expenditure levels. We've got maturities that come due in the first half of next year, which we expect to pay down and then we've, obviously, got maturities in '05 and '06 that we're working on at this moment. We've got a few more things to wrap up in August, final maturity on a small note, but, again, continued focus on reducing debt company-wide.

Then how does, you know, how does baying back stock fit into the equation?

I think at this point ,I think, given our debt position, and where we've taken it down to this point, we still have a ways to go. So, I think collectively the management here views that having less debt is certainly beneficial to our business, it's beneficial to our shareholders, beneficial to our debt holders. So, I think until we get the debt down to lower levels, that will take precedence over any share buy-back activities.

David, while it's not appropriate to consider that today, it's not something we're opposed to doing in principle. In fact, two years ago we were buying back our own shares.

What's your capacity to bay back shares? What's the authorization that's outstanding, right now?

That it's not an issue before us this year.

But you have the capacity to do it. I mean --

Yes.

Okay. The next question, not to beat the Barnett to death here.

We love to beat the Barnett to death. We love to.

Yeah, I think I misheard, was the five wells outside the heart of the play that you talked about, were they averaging 6 million a day, or is that collective?

That's collective.

That was collective. Okay, then second, how much capacity do you have left on your plan? The liquids.

This is Darryl Smette, and the capacity that we have left in our facilities out there is about 130 million a day.

Okay, so you have plenty of room to grow. Okay.

We also have some volume some areas don't require processing, so we can produce volumes in excess of plant capacity. Especially in the lean area, we do not take the lean gas through the processing plant.

The stuff to the south of the play, is that lean, if I remember correctly?

It's been leaner than the stuff that we've seen in the heart of the play, certainly, so far, but obviously we also have very few wells drilled out there, so whether that trend continues or not is yet to be seen.

Great. Thank you.

Thank you. Our next question comes from Aju Merti from Goldman Sachs.

Thank you. I think Larry had noted you were well on track to achieve the 4 to %6 organic growth target for this year, looks like with the development projection and momentum you should be well on track to do that in '04. I don't know if you can provide any comments or color on how you're seeing '04.

Just related to the question or comment about your desire to pay down further debt, it looks like if gas prices average 4 to $5 or higher, you will have significant free cash flow to both pay down a lot of debt and continue to fund your exploration development program. How do you think about the trade-off between continuing at the recent cap ex levels, versus paying down debt at, I guess, prices below those kind of levels?

Well, I think in terms, we certainly don't view it as an either/or, because we've been doing both this year, and because we agree entirely with the analysis you just did, that we're going to have the cash flow and the capacity to do both. Both, you know, this year, obviously, and next year. Of course, that's subject to the vagueries of commodity prices, which can vary. Certainly, we don't see anything out there that has any probability at all of changing our ability to do that.

Larry, not to interrupt, but clearly if commodity prices crash, that's a different situation, but it would seem like even in a 350 kind of world you all have the free cash flow to both pay down some debt and continue your cap ex program, that it just doesn't seem to be that big of concern unless commodity prices really crash. I don't know if you agree with that.

I agree with that entirely.

Any color on the '04 production outlook?

No, not really. It's too far in advance to start talking about '04. You know, we have a history of coming out with guidance that we meet, and we will like to continue doing that. We ave a lot of activity, a lot of things coming on stream in the second half of this year, and we want to see those come on stream before we come out with a forecast for '04.

I apologize, just one more question. I think Vince it noted the significant implied of the mid-stream business and I certainly appreciate the nature of that given your Barnett program. Any consideration given to MLP, you know, you retain the GP interest, you get to continue to control it, but maybe, you know, one can shed some debt to that and help the market realize that there is a significant value to this thing?

Yeah, if you look at where MLP is trading, we do look at that periodically, you know, the value of mid-stream business, if it were sold to an MLP or put in an MLP, would be somewhere at least a billion six to two billion, somewhere in that range. The problems that we have with selling it to a MLP is that that MLP would then have a monopoly that would sit there between us, our Barnett Shale field, and some of our other E & P operations and would extract a monopolistic profit before we could get our gas to market. While you would like to think you could devise a contract that would protect you against that, there are enough litigious people in this world that we're not sure we could do that.

You could not MLP it yourself to the public and retain the GP , as you've seen [INAUDIBLE] do with their VLI and that type of transaction?

We, certainly, could do that and that would eliminate that problem, but we would then have a significant conflict of interest problem. We have seen other people do that, but that worries us to put ourselves in that kind of a conflict of interest where we're on both sides of the table when we determine the exchange price between when the gas leaves the well and goes through the processing plant. It's real hard to serve those two masters, to resolve that conflict. We've seen other people try it, and that just makes us uncomfortable.

That's a helpful answer. Thank you, Larry.

I also might add, by controlling both we can, absolutely, assure that our wells are hooked up very rapidly. If someone else, and we see this in other fields, where you're dealing with traditional pipeline companies, the coordination and the speed with which your wells get hooked up with is more at their leisure than at our pleasure. By owning both sides of that, we can maximize our rate of return for our shareholders by having -- by controlling both of that, so the Wells are hooked up properly and timely.

Terrific. Thank you.

Thank you and our next question comes from Andrew Lees from RBC.

Let me interject here. This is the last question that we're going to have time for. We'll cut the call after this.

Good morning, guys. Now, with the much larger asset base, do you have any more plans, guys, maybe Jim, to call the crop?

Call the what?

Call the crop, assets.

I think from the standpoint of what we have done in the recent past in both companies, you've seen a process for companies, you've seen an attempt to try to rationalize the asset base. When we look at what is available, relative to what we have sold you won't see the kind of significant asset sales we had last year. What you will continue to see is a rotation out of less sufficient properties, but it will be something that, you know, doesn't necessarily hit the radar screen in terms of our total size. Somewhere in the 50 to 150 range a year in terms of millions of dollars. I might add that we had, exceptionally, large asset sales last year because neither Mitchell nor Anderson had been particularly aggressive at cleaning up the portfolios and dissupposing of properties that were inappropriate, that had become marginal. We, additionally, exited two countries, Argentina and Indonesia, where we were concerned about the future political situation in those countries, and with hind sight that was a very wise decision, conversely, we don't see any in the Ocean properties, Ocean has done a good job of keeping their assets cleaned and we cleaned our portfolio last year. So, any asset sales this year will be small. Our hour is up. As you know, in the past we try to limit this to an hour out of consideration to everyone's time, particularly, knowing it's a long reporting season. For those that we did not have time to answer your questions, we would, by all means, would love to answer them. So, call us back later today and we will get the right person to answer them. Thanks very much for paying attention to this call, and look forward to talking to you at the end of next quarter.

Thank you very much for participating in Devon Energy's Corporation second quarter 2003 results conference call. Have a great day, and you may now disconnect.