德文能源 (DVN) 2005 Q2 法說會逐字稿

Welcome to the Devon Energy Corporation's second quarter earnings conference call.

[OPERATOR INSTRUCTIONS]

At the request Devon Energy, this conference is being recorded. If you have any objections, you may disconnect at this time.

Now 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 welcome, everybody, to Devon's second quarter 2005 conference call and webcast. In today's call, our Chairman and CEO, Larry Nichols, will recap the quarter and offer some observations about the upcoming second half. Following Larry's remarks our President, John Richels, will review operating highlights for the quarter. And then finally our CFO, Brian Jennings, will cover the financial results and our outlook for the remainder of 2005.

Following the prepared remarks, we'll open the call up to questions. And as we typically do, we will limit the calls to -- call to about an hour. Want to remind you that we will all be around for the rest of the day to answer any follow-up questions that you might have. Before Larry gets started, I have a few procedural and compliance items to cover.

First, I want to call your attention to our 2005 guidance on production, crash (ph) utilizations, capital expenditures and expense items. Those estimates for 2005 were initially provided in our Form 8-K that we filed on February 2. And we updated that guidance with our Form 10-Q for the first quarter of this year. During the call today, we'll be updating some of our estimates based on the actual results that we saw in the first six months of the year, and our current outlook for the second half of the year.

In addition to the updates provided in today's call, we plan to file an 8-K early next week that will document all the details of our updated guidance.

In order to provide you a clearer picture of Devon's ongoing operations, we have provided separate guidance for the retained properties and the properties that we've divested in the first half of this year. Since those divestitures are substantially complete and we completed those in the first half, there's really not going to be any noise in the second half of the year from the divested properties.

Also I am required to remind you that all discussions of our plans, forecasts, estimates, and expectations are forward-looking statements as defined by the Securities and Exchange Commission. For a discussion of risk factors that could cause our actual results to differ from these estimates, I'll refer you to the SEC filings that I mentioned earlier which contain our published estimates. One final compliance item that I'll call your attention to, is that certain metrics that we will use in this call are defined as non-GAAP performance measures under the U.S. Securities Law.

When we use these metrics, we're required to provide reconciliation to the closest GAAP performance measures along with explanations as to why we view the non-GAAP measures used as useful. That information can be found at our website. That address is www.devonenergy.com. Finally, all references made to dollars in the call today are referring to U.S. dollars. That includes when we talk about our Canadian operations.

With those items out of the way, I'm going to turn the call over to our Chairman and CEO, Larry Nichols.

Thanks, Vince, and welcome everyone to our call today. Let me just start by saying that the second quarter of 2005, was clearly one of the best quarters in Devon's history. In the second quarter, we increased daily production rate from our retained properties base by 3% on a year-over-year basis, and 5% on a sequential quarter basis.

We reported net earnings for the second quarter of $653 million. A 30% increase over last year's $502 million. Diluted earnings per share reached $1.38. The highest of any quarter in Devon's history and well above the first call mean. Earnings per share, in fact, were up 37% over last year's quarter. An even higher percentage rate than our earnings themselves, which reflects the results of our share repurchase program.

Cash flow before balance sheet changes exceeded $1 billion for what is now the eighth consecutive quarter. In addition, during the second quarter, we generated $1.7 billion of cash from oil and gas property divestitures, bringing the total to about $2 billion, and essentially completing the divestiture program that we announced last fall.

During the quarter, we deployed $1.4 billion of excess cash, repaying $427 million of debt, and repurchasing $1 billion of common stock. As of yesterday, we have completed the stock repurchase program that we began in October 2004. In total, we repurchased 50 million shares or a little over 10% of our shares outstanding as of the beginning of the program. And we completed this program in less than ten months, well ahead of our original 18-month schedule.

As we have said repeatedly, we are continuously weighing the various possible uses of our cash and select the mix of alternatives, that in our judgment, maximizes value per share. We obviously monitor both the M&A market and the property acquisition market carefully. Comparing the values that we see there to other alternatives.

Based upon our current assessment of those options and the internal land -- external landscape in which we operate, we believe that further debt reduction, additional repurchases of Devon shares, and a measured increase in our upstreaming capital are all the best choices. To this end, we announced today a second 50 million share repurchase program. We also announced that we're calling for the early redemption of $400 million of 6.75 notes due in March 2011. In addition, we're announcing an increase in our 2005 capital budget.

We said in our quarterly call in May that we would conduct a mid-year capital review. We have, in fact, identified additional attractive opportunities within our existing asset portfolio. And have updated cost estimates across the Company. As a result, we are increasing our 2005 capital budget for exploration and production expenditures. The revised forecast range is $3.2 to $3.4 billion, which compares to our previous forecast of $2.6 to $3 billion. A little over half of that increase is opportunity or project driven.

In the second quarter in Canada, we initiated the Iron River Developmental Project. In 2005, this year, we expect to invest about $30 million at Iron River, drilling 30 -- drilling 70 wells. Also in Canada, we are boosting our capital budget for the 2005 portion of the upcoming winter drilling program by $115 million to get a jump on the winter drilling program and capture additional drilling opportunities.

These opportunities are principally in the Deep Basin, where we've been seeing some very strong results with the drill bit. We are also allocating $30 million for newly identified shale plays outset -- outside the Barnett Shale. We're also stepping up activity in the Carthage area in east Texas, the Bossier play in Louisiana, and several other projects in the Rockies and the Gulf.

In west Africa, the operator has selected to purchase the FPSO that has been serving our Zafiro field rather than continue to lease it. Devon's share of the purchase price will be about $80 million, and will be offset by lower operating costs at Zafiro in the future.

The balance or roughly half of the increase in our capital forecast is attributable to higher service supply equipment and labor costs. We expect the capital that we are allocating to increased activity will result in both incremental production and incremental reserve additions. We now expect to add 360 to 390 million barrels of reserves through drill in extensions in performance this year. This raises the midpoint of our range by about 15 million barrels.

The associated drill bit capital, including the E&P budget, the Iron River leasehold purchase and capitalized interest in G&A, is now expected to come in between $3.7 and $3.9 billion. We are also raising our 205 production guidance. The previous estimate was that our retained properties would produce 217 million Boe during the year. We now estimate that our retained properties will produce 220 million barrels for the year.

With that, I will turn the call over to Devon's President, John Richels, who will review second quarter field operations. John?

Thanks, Larry.

The second quarter was another active one for Devon with the drill bit. We had 107 rigs running company-wide at June 30 with 97 of those rigs running in North America. Capital expenditures for exploration and development projects were $772 million in the second quarter and about $1.7 billion for the first six months. That represents a little over half of our revised 2005 E&P capital budget of $3.2 to $3.4 billion. These amounts do not include the $200 million that we expended in the second quarter for the Iron River leases.

We drilled 493 wells company-wide during the second quarter, 51 of these wells were classified as exploration wells, of which 90% were successful. The remaining 442 wells were development wells, and about 98% of those were successful. So we had another great quarter with the drill bit.

I will begin the operational highlights onshore with the Barnett Shale field in north Texas. We had 18 operated rigs running at June 30, up from 14 rigs in the recent past. Based upon our increasing confidence outside the core, we now have 12 rigs running in the noncore areas. Subject to availability, we plan to add additional rigs in the Barnett Shale both later this year and next year. Our significant presence as a midstream player in the Barnett continues to enhance our effectiveness in the play. Because there has not been much gas production historically in Johnson County, we are building out the gas transmission system as we drill in new areas.

In that respect, we're in the process of completing construction of the main transmission systems from our acreage in Johnson County to the trunk lines which will allow us to get our Johnson County wells onto production very quickly following completion. Our outlook for the Barnett continues to improve. During the second quarter, Devon's net Barnett Shale production averaged 560 million cubic feet of gas equivalent per day, with almost 55 million per day coming from outside the core. This is up from both the second quarter of 2004 and from the first quarter of this year.

We now believe that our net production will climb 5% from the second quarter level to 590 million cubic feet equivalent by the end of this year, and that production will grow by another 6 to 7% by year-end 2006, to somewhere in the neighborhood of 630 million cubic feet per day. Because the Barnett Shale is such a tight formation, we estimate that only 10 to 12% of the natural gas in place is now being recovered with current development practices. As a result, even small improvements in recoverability are very meaningful.

Just to put that into context, for example, a 4% increase in recoveries would add 1 Tcf of reserves to Devon from the core area alone. As we mentioned last quarter, one element of our plan is to improve recoveries in the core area of the Barnett through a 20-acre downspacing pilot program. The Texas railroad commission has approved our request for downspacing, and during the second quarter, our first 20-acre horizontal well came online at a very encouraging 2.8 million cubic feet of gas per day.

We're continuing to drill and we expect to have a 16-well horizontal infill pilot completed by year end. Should the pilot prove successful, we could have as many as 350 additional 20-acre horizontal locations to drill inside the core area. We're also initiating a vertical infill pilot in areas that are not accessible by horizontal infills.

Moving to another nonconventional gas resource in the Powder River Basin coalbed natural gas play in Wyoming, we continue to identify new development opportunities. We've drilled or deepened 113 wells through the first six months of the year. Devon's net production from the Powder River Basin is running about 70 million cubic feet per day.

We're also having good initial indications from a coalbed gas pilot project in Wyoming's Wind River Basin. This ten-well pilot targets the Mesa Verde coals. If successful, this play could have upwards of 200 Bcf of potential. We will keep you posted as we get results from that pilot.

Also in Wyoming in the Washakie Basin, we're gearing up activity again, after seasonal drilling restrictions were lifted in June. We plan to increase activity from four to six rigs in August. That will allow us to complete 55 to 60 wells this year. Our drilling efforts and improvements in the gas transmission system that are being implemented should boost Devon's Washakie production from about 82 million cubic feet per day in the second quarter to more than 90 million cubic feet per day by year end.

Moving to east Texas. In the Carthage area, we're running five rigs, and in June, drilled the forty-third well of the 93-well program planned for this year. We continue to increase production in this area with our successful Cotton Valley drilling program. Devon's second-quarter Carthage production averaged over 200 million cubic feet of gas equivalent per day, which is up 9% from the first quarter. We have a lot of running room here. Our inventory continues to grow, and we now have over 200 undrilled locations identified on our acreage. In addition, many of our Carthage wells have uphole opportunities that are behind pipe.

In the Bossier play in north Louisiana, Devon holds roughly 200,000 net acres. We've identified a half dozen prospect areas on our acreage, with each representing a several hundred Bcf target. During the quarter we initiated drilling on a 100% Devon-operated prospect in the north Vixen area. The well is down, and we're evaluating the results. We plan to drill additional wells on the prospect later this year.

Also we're now participating in a test of another Bossier prospect in the Vixen area to the south, where Devon has an approximate 50% working interest.

Turning to the Gulf Coast of south Louisiana, last quarter we told you about the Devon-operated Berwick discovery in the Patterson field. Initial production from this well was more than 5,000 barrels of oil equivalent per day, making this the highest rate oil well completed in the industry this year in the lower 48. This is a multimillion-barrel field -- discovery, that Devon operates with a 50% interest. We're currently conducting a simulation study to determine the optimum development scheme for the reservoir.

In south Texas, we drilled two successful exploration wells in Matagorda County and are just completing a third. Devon has 670 square miles of 3-D seismic data in the area. The well encountered 70 feet of net gas pay. And we expect it to IP at between 20 and 30 million cubic feet per day. This is a 100% Devon-owned prospect, and sets up four or five additional drilling opportunities.

Moving to Canada, we had significant production growth there during the second quarter. From our retained properties, that is, excluding production from the properties that we divested, total production was up about 4% year-over-year, and more than 6% from the first quarter of the year. This was achieved in spite of a very wet spring, and the resulting operational delays that many Canadian producers have encountered.

Now that things have dried out a bit, our summer drilling programs are well under way in most areas. At the end of June we had 18 rigs running in Canada, up from 14 rigs in April.

As most of you know, during the second quarter we completed a large leasehold acquisition from Exxon Mobil in the Iron River area of east central Alberta. Iron River is part of our larger Lloydminster cold flow heavy oil development area and is directly adjacent to the Manatoken Field where Devon has had excellent drilling results to date.

Iron River is a direct analog to Manatoken and provides us with a multi-year low inventory of low-risk drilling opportunities. We are just now gearing up activity at Iron River, but the results from our first wells have confirmed our expectations. So we remain very optimistic about this property's future.

As Larry already mentioned, we expect to spend about $30 million drilling 70 wells and expanding surface facilities during the second half of 2005. The property is currently producing about 3,000 barrels of oil per day, and we expect to grow production to about 30,000 barrels per day by 2010.

Also in eastern Alberta at our Jackfish steam-assisted gravity drainage heavy oil project, we began facilities construction during the second quarter and completed the preparatory work for the drilling of our first wells there. The actual drilling of the wells started in July.

I will remind you that Jackfish is a 300 million barrel project with full production of 35,000 barrels per day scheduled for 2008. At Wapiti in the Deep Basin we completed six wells in the quarter that are producing a combined 75 million cubic feet of gas per day net to Devon's interest. We have an 83% average working interest in these six wells.

Now in the category of new projects, we're actively evaluating Devon's coalbed natural gas acreage in south central Alberta. In the second quarter, we completed a 50-well, coalbed natural gas drilling program at Wimborne. This project targets the Horseshoe Canyon Coals and follows a successful four-well pilot that we undertook in 2004. We expect to drill somewhere in the neighborhood of 250 wells at Wimborne over the life this project.

We're also extending our Wimborne program with 16 coalbed natural gas wells planned in the rich Gadsby area, and we're testing the Mannville Coals in two other project areas at Halkirk and Oberlin. While it's too soon to judge the success of these coal gas projects, the potential resource is significant. We will keep you advised as we move forward.

Turning now to the offshore U.S., I'll begin with an update of our deepwater development projects, and then I'll review our Gulf of Mexico exploration programs.

First at Nansen, which is located primarily on East Break 646. We completed a four-well recompletion program with excellent results. The fourth and final well was brought online in early July. This well came online at about 20 million cubic feet of gas per day, and approximately 2,000 barrels of oil.

In aggregate, the program's increased production -- the program increased the production from Nansen by over 13,000 equivalent barrels per day, net to our 50% interest. At our Magnolia deepwater development project on Garden Bank 783, four wells were online at the end of June, producing about 12,000 equivalent barrels per day, net to Devon's 25% interest. These results continue to exceed our expectations, and we expect to have a total of eight wells onstream later this year.

In the eastern Gulf, we expect to begin drilling operations in the fourth quarter at Merganser in the the Atwater Valley area. Merganser will produce into the Independence Hub, which is moving toward a scheduled completion date in 2007. Devon has a 50% interest in Merganser, which is expected to contribute 50 million cubic feet of gas per day to the Independence Hub.

During the second quarter, Devon drilled both exploration and delineation wells in the Gulf of Mexico in the deepwater lower Tertiary trend, the deepwater Miocene and on the shelf. In the lower Tertiary, much of our 2005 activity is focused on delineating previous discoveries. These wells will provide the technical teams with data that is crucial for determining the future development plans.

Looking more specifically at a couple of the wells that we drilled in the lower Tertiary trend during the second quarter, we began drilling an appraisal to our 2002 Cascade discovery located on Walker Ridge 206. This well is still drilling, and the partners are evaluating the data that we're obtaining. The results of this well are considered confidential, so we're unable to provide any additional information at this time. As you may recall, we have a 25% interest in this prospect.

Also in the second quarter, we began drilling an appraisal to our 2004 Jack discovery, which is a lower Tertiary discovery on Walker Ridge 759. Despite delays from both hurricanes Dennis and Emily, the well is nearing its expected total depth of about 30,000 feet. A full-scale production test of Jack is now planned for early 2006, and we will participate with a 25% working interest.

Finally, at St. Malo, Devon's third lower Tertiary discovery in the Walker Ridge area, plans to drill a second appraisal well have been delayed by rig availability. And it now appears as though that well may not spud until early 2006.

Turning to the deepwater Miocene program, the primary target zone in our Chilcoud (ph) exploratory well appears to be noncommercial, and the well has been temporarily abandoned. This was a Miocene test on Green Canyon block 320. Devon has a 20% interest in the well. However, due to the contract terms, our share of the dry hole cost was limited to around $5 million. Our technical teams are currently in the process of evaluating the results for any secondary target potential.

On the deep shelf, our Joseph well on High Island 10 reached a total depth of about 25,500 feet. And the well has been temporarily abandoned while we evaluate the results. Devon has a 20% interest in this well, and our total cost was about $15 million.

Also, drilling continues on our deep shelf Cadillac prospect, located on Viosca Knoll 251. Recent hurricanes slowed down drilling operations during the quarter but we expect to reach the planned total depth of 25,000 feet shortly. Cadillac is targeting the Cotton Valley formation. Chevron operates the well and Devon has a 10% interest.

We had two shelf discoveries in the second quarter. First at Big Bend. This is the Devon-operated shelf prospect on Mustang Island, A-110. The well was drilled to 19,600 feet, and looks to be a discovery in the 30 to 50 Bcf range. We plan to complete the well and install production facilities with first production expected in late 2006 or early 2007. Devon has a 50% interest.

Our second discovery on the shelf came at our Racer prospect on West Cameron 575. The discovery well was drilled to about 16,000 feet and found pay in two objectives. The well was completed and brought online in early June. It is currently producing about 20 million cubic feet of gas per day, and Devon has a 100% working interest in the prospect.

It -- it also appears that we had a third shelf discovery after the end of the second quarter. This discovery is located on the Devon-operated Chopin prospect on Eugene Island block 334. Chopin is targeting the middle Pliocene sands and has reached its total depth of just under 13,600 feet. Logs indicate approximately 60 feet of net pay in the primary objective and completion operations are under way. Devon has a 100% working interest in Chopin, and we anticipate first production in the fourth quarter. This discovery is on trend with the Eugene Island 334B13 well that has produced 13-- sorry 33 Bcf to date and is still producing in the vicinity of 25 million cubic feet of gas per day.

I will wrap up the operational highlights with an update of our international projects starting in west Africa. Firstly, offshore Equatorial Guinea field-wide production at our Zafiro field remains very strong. Currently over 260,000 barrels of oil per day. Devon's net share is running just over 35,000 barrels per day, following a reduction in our net share during the second quarter, which was triggered by reaching a cumulative production threshold. We expect to reach the final production threshold at Zafiro in late 2006. And from that point forward, our share of Zafiro production will be stable.

Also on Block B, just to the south of Zafiro, we're drilling an exploratory well on the Esmeralda prospect. Esmeralda has gross, unrisked potential of more than 500 million barrels. Staying with Equatorial Guinea, we have exploratory wells planned this quarter on both Blocks P and N. These are moderate-sized prospects, but could be brought on production fairly quickly if successful.

Finally in west Africa, we plan to spud wells around year-end to test prospects on Block 10 in Angola as well as a second exploratory test on Block 256 in Nigeria.

Turning to Brazil, as we announced in late June, we've elected to proceed with the development of our 2004 discovery on Block BMC-8. This -- this development project should move ahead fairly quickly. In fact, we plan to initiate facilities construction as early as January 2006, with first production projected for the second half of 2007. This is roughly a 50 million barrel development. However, there's significant additional potential on the block and surrounding structures which we plan to test in the future.

In China, the Devon-operated Panyu project continues to exceed our expectations. Field production is averaging above 75,000 barrels of oil per day, with Devon's net share right around 17,000 barrels a day. Following on our previously announced plans, we drilled two shallow exploratory wells near our existing production during the second quarter. However, both were unsuccessful.

And finally in Azerbaijan where Devon has a 5.6% carried interest in the 5 billion barrel ACG oilfield, construction of the pipeline from Baku to Ceyhan is now complete, and gross field production reached 290,000 barrels of oil per day in the last week of June. Assuming $50 WTI, we could reach payout under our carried interest arrangements as early as mid-2007. Under this scenario, our net share of peak production would be about 35,000 barrels per day beginning at payout.

That concludes our operations update. Now I'll turn the call over to Brian to review our financial results. Brian?

Thanks, John.

I will begin by looking at the key drivers that impacted our second quarter financial results. And importantly, how these factors impact our outlook for the second half of the year. Please note that our second quarter results do include revenues, expenses, and capital expenditures associated with the divestiture properties. As I did in the first quarter, I will highlight both our reported results and the results attributable to our core retained properties. Let's begin with second quarter production.

In the quarter, we produced 58.3 million equivalent barrels or approximately 641,000 barrels per day. This was a 1.8 million barrels above the midpoint of our forecasted range of 56 to 57 million barrels. Second quarter production included 2.8 million barrels from the divestiture properties. That was about 0.5 million barrels greater than our forecast. The increased volumes are primarily related to the timing of property sales.

Excluding the production contributed by the divestiture properties, our retained properties produced 55.5 million equivalent barrels in the quarter. That exceeded the high end of our guidance range, and was 1.3 million barrels greater than our 54.2 million barrel midpoint. On a comparative basis, production from our core properties increased by about 20,000 equivalent barrels per day over the second quarter of 2004, and by about 28,000 barrels per day over the first quarter of 2005. A 3% improvement over the second quarter of last year, and a 5% improvement over the first quarter.

Based on our first half results and our outlook for the remainder of the year, we are increasing our full-year 2005 production forecast to 230 million barrels. That target includes 9.8 million barrels expected to be contributed by the divestiture properties.

Looking at our core properties, this translates to a full-year production forecast of 220 million equivalent barrels, up from our previous 217 million barrel forecast. With actual first half production from our retained properties totaling 108 million barrels, we are forecasting a 4% increase in second half production to 112 million barrels, split evenly between the third and fourth quarters. We expect to deliver this production growth in spite of a forecasted 600,000 barrel reduction for possible hurricane disruptions and a contractual 700,000 barrel reduction in Zafiro volumes that John mentioned.

In addition to increasing our 2005 production outlook, we expect a step up in activity that Larry and John described to increase our production in 2006 and beyond. We will quantify the production impact for future years in conjunction with the preparation of our 2006 capital budget.

Shifting to price realizations, during the second quarter, benchmark WTI oil averaged $53.23 per barrel. As we discussed in our first quarter call, oil price realizations in Canada continued to show weakness in the second quarter. For Devon, this weakness in Canadian oil price realizations was generally offset by stronger international price realizations. Consequently, our second quarter company-wide floating oil price realizations were pretty much in line with our previous guidance.

The unusually wide Canadian oil differential started to recover in June, and we expect to see continued improvement throughout the summer months. Our second quarter oil price realizations were also impacted by financial hedges. We entered the second quarter with 67,000 barrels per day of our oil production hedged. Devon's hedge position for the remainder of the year covers 64,000 barrels of oil per day, or about 40% of our expected oil production. As we previously discussed, these hedges expire at the end of 2005.

Moving now to natural gas prices, the benchmark Henry-Hub gas price averaged $6.74 per mcf in the second quarter, up 12% from the second quarter of 2004. Devon's realized gas price averaged $6.09 in the second quarter, or $0.65 under Henry-Hub. This puts our company-wide floating gas price realizations at the high end of our previous guidance range, nearly 92% of Henry-Hub.

Our strong gas price realizations were driven by better-than-expected realizations in Canada. Our natural gas hedge position had almost no impact on our second quarter results. In the 8-K we are filing this week, we will fine tune our guidance for both oil and natural gas price differentials.

In addition to strong upstream performance for the quarter, our marketing and midstream results once again outperformed our expectations. Our margin for the second quarter totaled $93 million. That was $15 million greater than the second quarter of 2004, and $8 million greater than our first quarter result. This robust performance was driven by higher commodity prices, greater gas throughput and lower operating costs.

Based upon the actual performance for the first six months of the year, we are raising our full-year guidance for the contribution from our midstream operations. We now expect our 2005 marketing and midstream margin to come in between $330 and $350 million. That's a $60 million increase over the midpoint of our previous guidance.

Now shifting to expenses, we've reported lease operating and transportation expenses for the combined retained and divestiture properties of $338 million or $5.80 per barrel in the quarter. This was down slightly from the $5.85 per barrel we reported in the first quarter. As many of our peers have disclosed, we are seeing pressure on the cost of services and supplies. However, for Devon the impact of divesting higher cost, noncore properties is more than offsetting these pressures.

Looking ahead, with the divestitures complete, we anticipate lease operating and transportation expenses in the second half of the year to come in between $5.50 and $5.70 per equivalent barrel. Second quarter DD&A expense came in at $8.48 per equivalent barrel. This was below our guidance of roughly $9 per barrel. While we are pleased with this reduction, we are maintaining our full-year guidance for oil and gas property DD&A at $8.60 to $9 per barrel, as we do expect cost pressures to push our DD&A rate upward in the second half.

G&A expense in the second quarter was $78 million. This was a $20 million increase over our first quarter expense. In our first quarter call, we highlighted several items that caused our reported expense in the first quarter to be lower than our expected full-year rate. Given the first quarter expense reduction, the quarter-over-quarter increase was not unexpected. Looking ahead, we expect G&A expense to average approximately $75 million per quarter in the second half of the year. Based on our first half results and this outlook, we are increasing our full-year G&A expense forecast by about 5% over our previous guidance to $275 to $295 million for the year.

Interest expense came in at $146 million for the quarter. Of that total expense, $30 million relates to the early retirement of our zero coupon debentures. We incurred a premium of $25 million to retire the debentures and we recognized a $5 million noncash charge related to the accelerated amortization of the debenture issuance cost. In the remaining two quarters of the year, we expect to report interest expense of $100 to $110 million per quarter.

Looking ahead with today's announcement to redeem our 6.75 notes, we would expect to record a one-time charge of $40 to $60 million in the third quarter related to the early redemption.

Our reported second quarter income tax expense was 35% of pretax income. 27% current and 8% deferred. The relatively high current portion is primarily due to taxable gains on the sale of oil and gas properties that closed in the second quarter.

We are providing a reconciliation table in today's earnings release, that shows the tax effect of these property sales and other items that are generally excluded from analysts' estimates. When you back out the impact of these items, you get an adjusted current rate of approximately 23%, and a deferred rate of 13%, for a total rate of 36%. Excluding the impact of the asset sales, our taxes remain in line with our full-year guidance.

Going to the bottom line, we've reported net earnings for the second quarter of $653 million, up 30% over last year's second quarter result. Diluted earnings per share were a record $1.38 per share, versus $1.01 per share in 2004.

The reported results, however, include several items usually excluded in analysts' models. After adjusting for those items, which are described in today's news release, we would have earned $1.41 per diluted share. This is $0.15 above the first call mean of $1.26 per share. Another extremely profitable quarter for Devon.

Our second quarter earnings per share were calculated based upon a weight average diluted share count of 471 million shares. Now that we have completed our first 50 million share repurchase program, we would expect our weighted average diluted share count to fall to approximately 453 million for the third and fourth quarters.

Before we open up the call to Q&A, I want to conclude with a quick review of our evolving cash position. We began the second quarter with cash and short-term investments at $2.5 billion. During the quarter, we generated cash flow from operating activities of $1 billion and added $1.7 billion from the sale of noncore properties, a process now completed.

Expenditures in the quarter totaled $2.5 billion, including capital expenditures of $1.1 billion, share repurchases of $1 billion, and the repayment of our zero coupon debentures. We ended the quarter with cash and short-term investments of $2.8 billion. A $300 million increase in the quarter.

Following quarter-end, we retired two maturing debt issues, totaling $269 million, and we repurchased $567 million of common stock, completing our 50 million share repurchase program. Even with over 800 million of incremental cash expenditures since quarter-end, we today hold $2.2 billion of cash and short-term investments.

We will utilize a portion of that cash balance to redeem the 6.75 notes and the 236 million of maturing notes in the fourth quarter. Bringing our total 2005 debt reduction to over $1.3 billion.

At this point, I'm going to turn the call back to Vince to lead our Q&A. Vince?

Thanks, Brian. Operator, we are ready to open the call up to Q&A.

Thank you, we'll now begin the question and answer session. [OPERATOR INSTRUCTIONS]

One moment, please, for our first question. [OPERATOR INSTRUCTIONS]

We don't have any questions in the queue. So if you'd like to ask a question, you'll get in quickly.

Jeff Hayden of Pickering, you may ask your question.

Hey, guys, just real quick. Wondering if you could talk a little bit about where acquisitions fit into the strategy going forward.

Yes, the question -- this is Larry. The question on acquisitions, obviously we've done a lot of acquisitions in the past. We look at acquisitions to accomplish two goals. One -- we want to buy properties that -- that fit, and that we can grow. You don't do acquisitions just for the sake of that. We've already built up a strong portfolio. But there -- there are always companies and assets out there that you would like.

That leads to the second criteria, the second hurdle, which is to make sure the numbers work. That it is accretive, that it adds value to the shareholder. At the current time, as we look at the opportunities that are out there in the acquisition and the M&A market, we think we can add more value by buying our own shares. We don't view the acquisition of Devon shares any differently than we view the acquisition of someone else's shares or someone else's assets. We want to increase the value per share to the Devon shareholder.

And at the moment, we find the best way to do that is to announce our second share buyback and to continue to pay off debt so that we can keep the debt ratios in line. Whenever we find an exception to that, as we did with Iron River, then we will certainly do it. But if we don't, we'll continue to buy back our own shares.

Okay. Thanks a lot, Larry. Congratulations on a good quarter.

Thanks.

Ken Carroll, Johnson Rice, you may ask your question.

Hey, guys. How are you doing today? Quick question on your Barnett Shale activities. You talked about you're up to 18 rigs by the end of -- by June 30 and you're looking to add more later this year. And even more Heckomer (ph) rigs in '06 . How is the rig market up there in terms of getting your hand on those Heckomer rigs? Do you expect to have any problems, or have you talked to folks already about lining up those rigs?

This is Steve Hadden.

We're able to manage the -- both the personnel and the -- and getting the rigs as you've probably seen. We've gone from about 11 rigs in January up to 18. We're continuing to focus on our safety performance and our operating performance on those rigs with our contract partners, and we're pretty pleased with that performance to date.

And we'll methodically go about making arrangements with additional contractors for additional rigs, and we expect really to have the same performance. So while we're -- we're very diligent in looking at getting quality rigs and quality people, we're getting good performance of the rigs we've received to date. And we expect that to continue as we slowly ramp up our activity in the Barnett in the second half of the year.

Got you. I guess my question was less a real performance issue. Though that's actually good information. I'm thinking actually getting your hands on the iron. I know some folks in different operating years have had to actually sign long-term contracts to have new rigs built to kind of handle their needs. Are you having any problems getting new rigs to -- to continue to ramp this up, or how does that look to you?

We haven't had any problems to date. We are looking at some different strategies as it relates to going a little bit longer term with our contracts. And also we are looking at other alternatives in the market.

But to date, we really haven't had a major difficulty. Again, we're going a little bit longer term on some of our -- on some of our contracts. And of course, our dominant position in the -- in the play really helps us with access to rigs.

Got you. Great, thanks, guys.

Yes, just to expand on that, you look at Devon's very large acreage position both in the core and noncore, and a rig owner realizes if he gets a rig on Devon's acreage he's going to be working there for a long time.

Right, right. Very good point. All right guys, thanks a lot.

Gil Yang of Smith Barney, you may ask your question.

Good morning.

You made some comments about new shale plays that are not Barnett. Could you just tell us what you can about those areas? What you've learned there and what the Bar-- what you've learned in the Barnett Shale has taught you about those areas?

Well, we -- there is just a -- certainly a large amount of information and experience and competency we've developed in the Barnett Shale from our involvement in that play since -- since really the beginning of the play.

And we have learned quite a bit about both the ability to identify some interesting plays and the ability to use some of our technical expertise to unlock those plays, either with drilling or completion, or even with some of the geologic and geophysical work that we do.

We're not at a point now that we can comment on those -- those new plays that we're looking at. Obviously there's things that we're very interested in. And -- and we'll share information with you when we're able to.

Yes, sir, I understand that.

Could you just give us some sense as to if you were to -- to risk the acreage that you have now, what kind of risk factor would you place on that acreage?

I really couldn't comment on that at this point.

Okay. Thanks .

[OPERATOR INSTRUCTIONS] One moment, please, for our next question .

Arjun Murti of Goldman Sachs, you may ask your question.

Thank you.

Just on the increased production out of the Barnett, I guess especially for the exit for '06, which I believe was 630 million a day. Was -- I don't think, but was there any potential in there for some of the downspacing you talked about in the core? Or is that primarily, I guess noncore, and I assume Johnson County-type increases relative to the expectations you laid out last September which were, of course, much more conservative?

Yeah, that -- that's generally the sense.

As we talked about before in our previous calls and last September, we're really going into the noncore area and -- and looking at that play with -- we have over 1,000 miles of seismic, square miles of seismic. We've really tried to understand that plan. Now we're accelerating into that play as we talked about earlier. So that -- part of that is the noncore story and the growth in the noncore. And that's probably the principal factor that you'll see. We're very interested and intrigued by the first two wells that we've drilled as far as the 20-acre downspacing. We're encouraged by those results, but it's very early in that pilot.

And as John mentioned, we'll drill another 16 wells this year and really look at that as -- as another opportunity and really increasing the recovery in that -- that really strong position we have in the core area. As we hopefully will have some success with that 20-acre downspacing.

In terms of the noncore, I guess I've always thought your previous projections were really reflecting one of conservatism and to an extent you have more results now, you're willing now come up with a higher forecast and drill more wells.

Is that it, or are you seeing some material additional betterment of results than maybe you might have thought before? Or maybe it's both.

Well, I think it's both. As you know, when we look at plans we look at them on a risk basis going forward. We have over 1,000 locations that we've identified on a risk basis yet to -- yet to explore and drill in the noncore area. John mentioned another 350 that could be potential if the 20-acre downspacing works.

So as we have -- gone and run a lot of seismic across this acreage and that information has been coming in, we have drilled wells in key areas and done some scientific work on those. And that, of course, gives us more confidence, both the results and the technical work that we've done, has given us more confidence in those results. And we're willing to put those results on the table that reflect in that new production forecast.

That's great. Thank you very much .

Michael Kahn (ph) of AR Schneider, you may ask your question.

Yes. Actually, this is Arnold Schmeidler. Hi, Larry, congratulations on a great result.

Thanks.

I had three questions.

First of all, and I apologize if you've already covered this because I couldn't come in in the beginning. The Ocean Energy properties that you've got, do you still have some -- do you have any idea that you can share with us how many prospective blocks that are really number one targets for you out of the total? I think you had acquired over 500 when you bought the company.

The -- Ocean was closed over two years ago. And what was -- to do a successful integration, you quickly forget what you own and what the acquired company owned and merge them together in your own minds and the Company mind. You can look at Ocean in a variety of ways.

What we bought onshore in the Bare Parch (ph) up in Montana and the Carthage area, clearly has outperformed our expectations at the time. It was not an area that Ocean worked on that much. And that's an area of our specialty, and we've really done well there.

In the Gulf of Mexico, you heard earlier about Nansen and its outperformance, Magnolia, the same thing. Those are outperforming what we expected. The acreage that Ocean added in the -- the deep gulf added to the position we already have. We're -- we remain excited about that. As we continue to do -- drill these delineation wells and look for production tests next year. So that's going -- going better than expected.

If you move internationally, Zafiro, the major international field that Ocean had, again, has outperformed expectations. With regard to the undrilled blocks there, most of them remain undrilled. One of the more exciting ones, as we said earlier, Esmeralda, we're in the process of drilling now with Exxon, the operator. That has great potential. It's also an exploration well. And we plan to drill a lot of the others in the next 18 months.

So the undrilled blocks before one can really -- you can look at everything except the undrilled blocks, in -- in west Africa and say it exceeded our expectations. With the undrilled blocks, that's a really an exploration play, and it will take 18 months and a lot of different wells before we can pronounce any final judgment on that.

Okay, fair enough.

Now, had you gone into the reserve replacement ratio before?

Yeah, we discussed that earlier in the call. And we are -- we have increased our forecast for the reserve replacement for this year.

Okay.

And lastly, what would you estimate on the share repurchases you're really paying for a barrel per oil equivalent?

Yes, this is Brian Jennings. I can take that.

When we look at the Company, we obviously have a significant marketing and midstream business that we're effectively repurchasing a part of that with each share. But we think that number, given our expectations for reserve this year is something that approaches $10 to $11 a barrel, maybe $10.50 a Boe of our reserve base which, of course, we have a relatively low component of PUD. So we view that reserve base as being very high quality and very valuable.

Very good. Excellent. Well, keep up the good work, and we appreciate all you're doing. Thank you.

Ben Dell of Bernstein, you may ask your question.

Thank you. I just had a couple of questions.

The first, in the Gulf of Mexico, do you currently have all the rigs you need to fulfill your drilling program? And -- and what sort of day rates are you looking at paying for some of those rigs?

Yes, this is Steve Hadden.

We're currently able to drill our program, and we're able to get our rigs for 2005 and as we look forward into the -- into 2006. We've seen rate increases that have -- that have affected us, but generally we're -- we have rigs that are drilling that are either under contract already and we're really not out in the spot market quite a bit.

So we're seeing some increases -- in the Gulf we're probably seeing well -- total well cost increases that can be as much as 15% or 20%. Of course a rig's a portion of that.

If you want to go to the spot market and not necessarily what we're experiencing directly on our bottom line, we're seeing rig rates that have gone up as much as 50 to 80% on some of the rigs -- on rigs in the Gulf.

Okay.

Maybe I could ask a separate question on your coalbed methane production in Wyoming. Yes, we've seen that recently tail off and a lot of operators have been talking about issues around the water handling and legislation there.

Do you have a view for what the outlook is in your coalbed methane? Do you see those volumes coming back up, or do you sort of see the best-case scenario now holding that static?

Yes, we see our volumes really -- we've really stabilized the decline that we've seen over the last year to 18 months or so. We're doing a lot of work in our existing positions and deepening wells or opening new sections and getting some good incremental production there.

We think over time in the longer term with the Big George and the development that we'll see there, that in the longer term, we'll turn that around a bit and hopefully see some increases in our overall net production out of the Powder.

Okay. And maybe lastly, one on a slightly different area.

On the international exploration stand -- side of the business, the historic numbers haven't been that impressive in terms of exploration success.

Have you been looking at ways of focusing the portfolio down or concentrating on sort of the elephants or the high prospectiviting (ph) wells to try and improve that overall outlook and in terms of Regises (ph) sort of a dry hole core (ph).

Absolutely. We've been continually trying to improve -- and improving the portfolio. We've exited certain plays or areas that we don't think are prospective. As Larry mentioned, we have quite a few blocks in west Africa, where we're focusing mainly in offshore Nigeria. Equatorial Guinea, in that area. And then down south in Angola.

And we're going to test a -- a couple of interesting and really significant prospects there. And as I think we mentioned in the call, in -- earlier, in Brazil, we've had a real focused effort there. Had exploratory success on BMCA to now we've moved to a commercialization phase there. You'll see us continually evaluate the results.

We do consistent look-backs, we do peer reviews to risk the opportunities. And look at the Devon portfolio across the world to try and really focus our capital and our people on the best opportunities. You'll see us continue to do that as we move through these different plays and test some of our ideas.

Okay. Just on the Sao Tome, am I right at assuming you're really at the forefront of the toe thrust in the Nigerian delta system there? And that your structuration tends to decrease as you go out into the deeper water? And if so, do you have a feel for what the average field size is, you're targeting in? Does that need to come in as gas rather than oil -- oil rather than gas to make those sort of prospects economic?

You know, the field size issue can range -- I think we've put out numbers before that the field size range anywhere from -- from 3 to 400 million barrels on up to the billion barrel field sizes that you've seen in some discoveries throughout that area and that trend. I think that when you talk about the risk of gas versus oil, that's a risk that we try and manage.

And we look at the maturation of the source rocks and what that means relative to gas versus oil and do our best to try and manage that risk. So it really is prospect dependent and area dependent depending on which block you're looking at even as you move into the JDZ.

Great. Thank you very much.

Frank Kuzma (ph) of RBC, you may ask your question.

Yes, I had a couple quick questions about Nigeria. With Shell's discovery right near the border, how does that affect any other type of drilling you guys have going on there? And in Nigeria, how is that type of structure unitized when it's across the border?

And second question about Nigeria is, if you can provide any type of details on your target that you're drilling for in the fourth quarter.

Yes, this is Steve Hadden again. When we look at Nigeria and you talk about the -- I think you're referencing the Shell discovery on the block to the north of our block 256 --

Yes.

To my knowledge there is no unitization effort that would go on there. As it relates to 256, 256 is a very, very large block for us. It's probably equivalent to about 125 Gulf of Mexico blocks. We have multiple prospects on the blocks. We drilled one which was our tarry (ph) well which was a dry hole in the first quarter.

But we were very encouraged by the information that we got from that well, and we're in the process of -- of preparing to drill another prospect on the same block. We are aware of the Shell announcement. And of the information that they have. We do have prospects in that area. We're making sure that we understand all that information, including the work that we got from our tarry well, and we'll integrate that into the selection of our location for this upcoming well in the fall.

Okay.

And also, just a quick question on the production test for the -- for the Jack well. Can you throw out any details as to -- what would we be expecting as a good result there? And how long would that test be for?

Well, I can't really talk in detail about that. A good result would be commercial rates. We're hoping that the -- that the well will test and demonstrate that it can produce at commercial rates over a long-term period without a significant draw down. I think we've said all along that we believe that these discoveries have that commercial potential, and we've seen nothing that really detracts from that thinking.

And that we think we'll continue to see success. The test is scheduled for the first half of next year, and we look forward to the results. But I don't have anything, any other details to share with you about the test at this time.

Okay. Thanks.

Operator, we've got time, we'll take one more question. Looks like we're at the top of the hour.

Thank you. Our next question comes from Shawn Reynolds of Van Eck.

Just snuck in here, guys. Hey, you've obviously decided that the best use of your free cash is not to go towards , M&A, or large M & A.

I'm just wondering your thoughts on who -- who are -- what companies, what individuals are participating in acquisitions right now and if you have any thoughts or any comments about Canadian royalty trusts dropping down into the U.S. to make -- to participate in the market down here.

Yes, Shawn.

The decision is -- is a day-to-day decision. As I said at the -- in the first question, it is not a -- who knows whether it will be a permanent decision or not. It's just that today we look at the opportunities. We look at the value that we see in our own -- our own Company, in our own assets, which I think the performance of is becoming increasingly clear. As it has with this call.

And we think there's better value that we can add to the shareholders by buying our own stock as opposed to buying someone else's. If and when we find some other company, or group of assets that we can buy that would be better, then we will go do that. But if we don't find that, we'll continue to buy our own stock.

Yes. I don't disagree with your decision right now. I'm just wondering at what point do you think prices will let up a little bit, that it starts to become more attractive.

It's -- it's a day-to-day decision. There's not much more you can say to that other than we want to produce the best results. And we'll choose whatever alternative that we think produces the best results.

Right.

And do you have any thoughts at all or any comments about the Canadian royalty trust? I think John might have some view on that.

Shawn, I guess the only thing I would say is there's been a lot of talk about the Canadian royalty trust coming down here and moving this market along. But what was interesting, when we looked at our own disposition program which sampled a lot of the market, we got roughly the same kind of metrics in the U.S., for the U.S. properties that we did in Canada. And in Canada, that royalties for us were obviously very active.

So I think that just points to the fact there's a very competitive market. And there's a lot of activity in the market. Even in -- with or without the royalty trust.

Okay, great, thanks, guys.

Okay, well we've always tried to keep this call to an hour. So if there are any -- if there were any other questions out there, call us privately after this call.

Just in summary, let me say that there really were quite a few positive surprise from today's call, in our view. Our high-quality North American assets have continued to consistently generate organic growth. They have outperformed our expectations by a wide margin in the second quarter, which has led to both positive earnings and cash flow surprises.

Second quarter production, as Brian described, exceeded our forecast with core properties producing at a daily rate, 5% higher than the first quarter. We are increasing our exploration production budget, and we're increasing our production guidance for the second half. Which, yes, we estimate to be 4% higher than the first half from our core properties. We're also increasing our projected reserve additions for the year.

In the Barnett Shale, we expect our daily production to increase by 12% over the next 18 months. We're increasing our guidance on midstream profitability margins by 21%. At a time of increasing cost pressures, our lease operating costs per barrel actually came down in the second quarter. And we project that the second half will remain below the first quarter. With our significant free cash flow, we've announced our second $50 million share repurchase program and additional accelerated debt. All in all, we think it's a pretty good second quarter. Thanks very much for your attention. Good-bye.