德文能源 (DVN) 2004 Q4 法說會逐字稿

Hello, and welcome to Devon Energy Corporation's fourth-quarter and year-end earnings conference call. At this time, all participants are in a listen-only mode. After the presentation, we will conduct a question and answer session. (OPERATOR INSTRUCTIONS). At the request of Devon Energy, this conference is being recorded for instant replay purposes. If you have any objections, you may disconnect at this time.

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

Thank you. Good morning, and welcome to everyone to Devon's fourth-quarter and year-end 2004 conference call and webcast. Before we get started, as usual, I have a few introductory remarks, and following those, Larry Nichols, our Chairman and CEO, will give you a brief overview of our results and review our year-end reserve report. Following Larry's remarks, our President, John Richels, will cover the operating highlights. And then finally, Devon's CFO, Brian Jennings, will review the financial results and our 2005 outlook. Following Brian's comments, we'll open up the call to your questions. And, as we have done in the past, we will limit the call to one hour. However, we will be available throughout the day for follow-up questions that you may have.

I want to first point out that we're filing a Form 8-K this morning. It includes Devon's 2005 forecast for oil, gas and NGL production, price differentials, expenses and capital expenditures. That information will be distributed by e-mail to our distribution list, as soon as we have confirmation from the SEC that the 8-K has been accepted for filing. During the call, we will refer to some of the forecast out of the 8-K, but the 8-K captures it all in one document for you. The 8-K will also be available on our website later today, for those of you that don't receive it via the e-mail distribution.

I am obliged to remind you that the forecast and the other outlook information that we will provide in this call are forward-looking statements. While we always strive to give you the very best information possible, when we provide forward-looking information, we run the risk bad are actual results will differ. For a discussion of the risk factors that could cause our actual results to differ, I will refer you to the Form 8-K that we're filing.

Most of you are aware that we are currently in the process of a pretty significant oil and gas property divestiture program, and we expect all of these divestitures to close during the first half of 2005. To provide you with the most flexibility, especially those of you that keep models on Devon, the 8-K will have separate forecast for the assets we are keeping and for those that we're divesting. As we move forward and announce the results of the divestiture program and have closing dates and so forth, we will provide information on the expected impact on our go-forward reported results.

During the call today, when we refer to dollars, even when we are talking about our Canadian activity, we will speak in US dollars.

And then one final item. I need to point out that some of the measures that we will provide in our call today, as well as some in the press release, are non-GAAP performance measures as defined under US securities law. In accordance with the rules, when we refer to such measures, we also provide reconciliations to the closest generally accepted accounting principle performance measures, along with explanations as to why we view the non-GAAP measures useful. That information can be found on our website; that address is www.DevonEnergy.com.

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

Thanks, Vince. Those of you that have followed Devon for some time know that our strategy has been to build a foundation of core assets in North America that could consistently deliver a cost-efficient drill bit growth and provide a strong source of free cash flow. We wanted to balance those core assets with measured investments in high-impact projects, which we are currently pursuing in the Deepwater Gulf and in international areas. We also wanted to be in a position to deploy our excess cash to deliver incremental value to shareholders by strengthening the balance sheet, by increasing dividends and by repurchasing shares. Our 2004 results reflect the fruits of the continuation of this strategy.

By most measures, 2004 was really the best year in Devon's history. The Company delivered all-time record production, earnings, earnings per share, and we had a very successful year with the drill bit. We produced, during 2004, 251 million equivalent barrels of oil, gas and NGLs. This represents a 10 percent increase over 2003 production. We hit this target in spite of a hurricane season in the Gulf that caused us to defer about 1.1 million BOE. Net earnings for the year climbed to 2.2 billion or $4.38 per diluted share. Earnings for the fourth quarter also set an all-time record of 673 million or $1.35 per diluted share. When you adjust for the items that analysts typically omit from these estimates, earnings are lowered slightly to 655 million or $1.31 per diluted share, a number that handily beats the first call mean estimate of $1.20 per share.

Cash flow before balance sheet changes was 1.3 billion for the quarter and 4.9 billion for the entire year. We funded all of our capital requirements, we repaid nearly one billion in debt, and we ended the year with 2.1 billion in cash on hand. During 2004, we easily surpassed the targets that we'd set for ourselves for net debt reduction, and we enter 2005 with our balance sheet in excellent condition. As 2005 progresses, we will continue to put the Company's cash to work where, in our judgment, it maximizes the best value per share.

2004 was an excellent year for Devon, from a drilling perspective. Not only did we beat our reserve addition and capital efficiency targets, but we moved our high-impact projects forward to the point where we can reasonably expect to see some significant reserve additions from these projects in 2005. This is what we were forecasting all during 2004.

Moving now to Devon's 2004 reserve additions, through discoveries and extensions, we added 268 million BOE. In addition, non-price-related reserve revisions -- that is to say, our performance revisions -- added another 45 million BOE of reserves, and that really speaks to the conservative nature with which we book reserves when we initially add them to the books. So our total 2004 reserve additions from discoveries, extensions and revisions other than price totaled 313 million BOE. This number of 313 million exceeds the top end of the target range that we provided in September, which was 250 to 300 million BOE. The 313 million barrels of additions is also well in excess of the 251 million BOE that we produced in 2004. The drill bit cost associated with the 313 million BOE of additions was $2.8 billion.

Given that the SEC has very recently -- indeed, in the last few weeks -- redefined finding and development costs, we won't calculate the per-barrel drill bit cost for you in the historical manner. Suffice it to say, however, that these results were slightly better than the most favorable end of the range that we communicated to you in September.

I said earlier that our strategy included building a basic of high-return core assets in North America and onshore that had repeatable opportunities for growth in both reserves and production. To provide better transparency in the performance of these assets, for the very first time this year, we're going to break out our US reserves and capital activities between the US onshore and the US offshore.

Let me first address the US onshore, where we added 159 million BOE of reserves through drill bit and performance additions. This number compares to 112 million BOE of production for the year. The 159 barrels of drill bit and performance additions was achieved with drill bit capital of a little over 1.1 billion. Regardless of how you define finding and development costs, we think you will agree that Devon's capital efficiency with these assets is very attractive. These results were driven by the performance in our core assets across our US onshore focus area. In Barnett Shale, we added 60 million BOE of proved reserves from the drill bit and performance-related revisions. These additions resulted from horizontal drilling outside the core and the continued performance of our core area. The 60 million BOE of additions in the Barnett Shale compares to a little over 34 million BOE of production for the year. In 2004, we drilled 200 Barnett wells, and we expect to drill another 225 wells in 2005. With over 320 million barrels of proved reserves, and with our dominant position in the core area, and with our 415,000 net non-core acres, Devon continues to have by far the best position in the Barnett Shale.

Another significant growth area for Devon is our Carthage area in East Texas. In 2004, we added 28 million barrels from discoveries and extensions, and we increased production to 11 million BOE, which is up 60 percent over 2003 production. We drilled 92 wells in Carthage in 2004. We plan to drill 106 wells in 2005. We have several years of drilling inventory, a 40-acre high working interest infill locations and are continuing to build our drilling inventory.

In other areas, in the Rockies, our Washakie Field in Wyoming continues to grow. Washakie reserves additions from discoveries, extensions and performance revisions were 14 million BOE. This compares with production of 5 million BOE during 2004. We tied in 62 wells in 2004, we have 84 wells planned for 2005, and we have an inventory of more than 300 locations. Like the Barnett Shale and like the Carthage area, Washakie is an area where we have sizable acreage positions with high average working interest, extensive drilling and protection experience, and is an area that is delivering both production growth and economical reserve growth year after year.

Other US onshore areas where we added significant reserves include the Permian Basin, where we drilled 150 wells and added 31 million BOE; South Texas, where we drill 78 wells and added 7 million BOE; and the Powder River Basin, where we drilled 155 wells and added 5 million BOE.

Let me now turn to our Canadian assets, which are also yielding excellent results. Our Canadian drill bit and performance revisions totaled 122 million BOE. Production climbed 3.6 percent in 2004 to 65 million BOE. The 122 million BOE of additions was achieved with drill bit capital expenditures of $945 million.

Much like our growth in the US, our growth in Canada was driven by assets spanning across the base of our large-scale, high-quality oil and gas properties that we have assembled over the years. The Deep Basin in West Central Alberta is one example. In 2004, we added there 30 million BOE from drill bit and performance revisions, while we only produced 12 million BOE. The 12 million BOE production marked a 30 percent increase over 2003. Year-end proved reserves reached 98 million BOE. We drilled 187 wells in the Deep Basin in 2004, and have another active program planned for 2005. Here again, we have lots of running room with our leasehold position of over 480,000 net undeveloped acres.

Other areas in Canada where we generated significant reserve additions include Lloydminster, where we drilled 191 wells and added 15 million BOE; Northeast British Columbia, where we drilled 115 wells and added 10 million BOE; the Central Plains, where we drilled 90 wells and added 11 million BOE; and the Peace River Arch, where we drilled 149 wells and added 7 million BOE.

In summary, during 2004, our North American onshore assets produced 177 million BOE, while we added 281 million BOE with the drill bit and performance revisions. That's 280 million that we added in relationship to 177 of production. We did that with drill bit capital of $2.1 billion. Devon's North American onshore assets are an engine of steady, cost-effective growth, and these assets represent about 70 percent of our current production and almost 80 percent of our proved reserves at year end.

The balance of the our operations, the Gulf of Mexico and international assets, are focused more on building future growth through high-impact exploration. Looking first at the Gulf, we held production steady in 2004 at 39 million BOE. We booked 5 million barrels of new reserves in the Gulf with drill bit capital of 460 million. Much of our investment in the Gulf in recent years has been on longer-term exploration activities. While these investments have resulted in some major discoveries, the projects had not yet matured in 2004 to the point where we could book reserves or where they would start showing production. We are optimistic that we will begin booking reserves from some of our high-impact Gulf exploration in 2005.

In addition, we are in the process of divesting some of our non-core Gulf assets. Our remaining Gulf assets will have much better capital efficiency and a much better production profile going forward. John Richels will talk more about our Gulf activities in a moment.

Turning to our international division, here we added 27 million BOE through extensions, discoveries and performance revisions. For the year, our international production nearly doubled to 35 million BOE. China and Equatorial Guinea were the big growth drivers. We also removed a significant amount of international reserves from our books due to price revisions, and I will cover this in a second. Our 2004 international drill bit capital totaled $288 million, with exploration costs representing almost all of that. In the Gulf of Mexico, most of our international exploration spending on projects where the initial capital outlays precede any potential (ph) reserve bookings by several years. That's true in both the Gulf and in the international. And John will talk more about international activities in a moment.

To recap companywide drill bit activities, when you add the Gulf and international results to North American onshore, you'll find that during 2004 we produced 251 million BOE. We added 313 million BOE with drill bit and performance revisions and had associated drill bit capital expenditures of $2.8 billion.

Let me now talk a little bit about price revisions. You may recall that in the estimation of year-end reserves, the SEC requires a producer to use oil and gas prices that existed on December 31 and then hold those prices flat forever. Year-end 2004 WTI benchmark oil prices were significantly higher than at year end 2003. At the same time, higher differentials widened to record levels. This combination resulted in companywide downward price revisions of 76 million BOE.

In our September analyst meeting, we pointed out the high-impact oil prices in our international production sharing contracts. Under these contracts, oil companies such as Devon are entitled to recover their costs from the early production from a project. After the company recovers its cost, and host government bites (ph) in for a larger share of production. So when prices rise, oil companies will recover their costs with fewer barrels. This results in a reduction to booked reserves. On the other hand, it is important to note that in spite of this result, higher prices are not bad for Devon. While the reserves booked for the international projects go down, our rate of return goes up. Also, if oil prices decline in the future, we can rebook these reserves. Total international booked reserves were reduced by 46 million barrels, due to higher year-end oil prices, with Azerbaijan accounted for 40 of the 46 million.

Heavy oil economics in Canada also accounted for pretty hefty downward price revisions. This resulted from a pricing anomaly that occurred around year end. The differential for heavy oil has historically averaged about 30 percent of WTI. In late 2004, it increased to the highest level in history, and at December 31, heavy oil differential was over 54 percent of WTI. As a result, producers across Devon have taken heavy oil reserves off the books at year end. This accounted for 45 million barrels of Devon's downward price revisions. The 91 million barrels of downward-price-related revisions was partially offset by positive price revisions of 15 million barrels, which brings our net downward price revisions to 76 million barrels.

Clearly, our 2004 drill bit results were a significant improvement over 2003. We expect, in 2005, to build on our 2004 success, with total reserve additions targeted in the range of 330 to 380 million BOE, at a drill bit cost of roughly 3.1 billion.

Now, I will turn over to John Richels, who will cover some of our operational highlights.

Thank you, Larry, and good morning. Let's begin with the Barnett Shale in North Texas, where we continue to be the most active operator. We had 14 operated rigs running at December 31st. There were 9 rigs running in the core area and 5 outside the core. During the fourth quarter, we completed 45 wells, of which 34 were in the core and 11 were outside the core. Initial production rates on the non-core horizontal wells completed in the fourth quarter averaged 1.9 million cubic feet per day per well, and Devon's fourth-quarter Barnett Shale production averaged 554 million cubic feet of gas equivalent per day, with about 43 million of the total coming from outside the core. Wet and freezing weather caused some delays in getting equipment on and off locations in the fourth quarter, but the full-year production in 2004 was still up above 3 percent over 2003.

At December 31, we had 1,900 wells producing in the Barnett Shale, and of these, 144 were horizontals, 87 of those were in the core and 57 were outside the core. Looking to 2005, we expect our capital investment in the Barnett, including land and G&G expenditures, to increase to about 360 million, and we're allocating more than half of that capital to the non-core areas. Inside the core, we expect to spend approximately $145 million, which translates into approximately 70 vertical wells and 55 horizontal wells. In addition, we will be refracting about 30 wells inside the core. Outside the core, we plan to spend approximately $215 million and will drill about 100 horizontal wells. We expect our 2005 Barnett Shale production to be roughly equal to 2004, but with production growth accelerating in 2006.

In Canada, our winter drilling activity is now at its peak, and we are more active than we were at this time last year. We were running up to a record 63 Devon-operated rigs in Canada and January versus 47 rigs in January of 2004. Because many of the areas in which we operate are winter-only access, December through March, as you will recall, is typically our most active period in Canada. We expect to drill about 400 wells during this year's winter program and spend about $475 million. This is roughly half of our full-year Canadian capital budget.

Our winter drilling is focused in four major areas -- the Deep Basin, the Foothills, the Peace River Arch and Northeastern British Columbia. At our Jackfish thermal heavy oil project in Alberta, we received final regulatory approvals in late December. Our 2005 capital expenditure budget includes about $160 million of one-time upfront costs for Jackfish site preparation and the construction of the central facilities. Construction of our first well pad will also commence later this month.

Just as a reminder, Jackfish is a steam-assisted gravity drainage project that is 100 percent owned by Devon. In phase one of the project, we plan to ultimately book 300 million barrels of proved reserves, and Jackfish will produce about 35,000 barrels per day when it's fully onstream in 2008.

Turning now to the offshore US, I will begin with an update on a couple of our deepwater development projects. First, the Red Hawk feldspar (ph) at Garden Banks 877 came online in mid-July, and continues to produce at facility capacity in excess of 120 million cubic feet of gas per day. Devon has a 50 percent working interest in Red Hawk.

At our Magnolia deepwater project on Garden Banks 783, the first development well was brought online in early December, and that well is performing very well. It is now producing 12,700 bales of oil and about 23 million cubic feet of gas per day. The second well is still cleaning up, but it's making 13,000 barrels of oil and 16 million cubic feet of gas per day. Combined, this is over 7,000 BOEs per day net to Devon's 25 percent interest. We expect to have a total of 8 wells onstream later this year. Magnolia is in about 4,700 feet of water. It's the world's deepest tension leg platform, and it's operated by ConocoPhillips.

Turning to our deepwater Gulf of Mexico exploration, our upcoming wells in the lower Tertiary trend are focused on appraising some of our previous discoveries. Later this quarter, we expect to begin drilling an appraisal well to our 2004 Jack discovery, and we also have a follow-up well to the 2002 Cascade discovery planned for the first half of 2005. Another well on the St. Malo prospect is also planned for later in the year. We expect one of these lower Tertiary discoveries to be production tested this year, and we remain optimistic that one of the projects will advance to the development stage and warrant reserve booking in 2005. In addition, we hope to test at least one additional lower Tertiary prospect during the year.

Also in the deepwater Gulf, I will update you on the Miocene exploration wells that we talked about last quarter. The Macaloo (ph) prospect on Mississippi Canyon Block 937 is a 30,000 foot subsalt Miocene prospect in about 4,200 feet of water. This well is part of our joint venture with Chevron-Texaco, and we have a 12.5 percent working interest in the well. We are currently setting casing below 20,000 feet.

The Chocute (ph) well on Green Canyon Block 364 was initially delayed due to rig availability, but the well has now spudded. Chocute is another 30,000 foot subsalt Miocene test, operated by Kerr-McGee, and it sits in about 2,500 feet of water. Devon has a 20 percent working interest in this prospect but, as I mentioned in November, a partner will be paying about 75 percent of our share of the costs.

On our Joseph (ph) prospect, which is a deep shelf prospect located at High Island Block 10, we are drilling ahead again after mechanical problems caused us to sidetrack. We are drilling below 15,500 feet en route to 24,000 feet. You may remember this Shell-operated prospect is targeting lower Tertiary-age stands just off the coast in only 30 feet of water. Devon has a 20 percent interest in the prospect.

Staying with the deep shelf, Big Bend is a Devon-operated deep shelf prospect located on Mustang Island A110 in about 300 feet of water. Big Bend is targeting middle Miocene sands, with an expected total depth of 19,600 feet. It is currently at about 13,700 feet. We have 50 percent of that prospect, and it is on trend with a shallower field on the same block that has produced in the neighborhood of 180 Bcf of gas.

Also on the shelf, we drilled a successful follow-up to our Star discovery on West Cameron 165. The A7 well has reached a depth of 12,250 feet and has found over 100 feet of net pay. We are drilling it down to a planned total depth of 13,900 feet. The first well at Star, the A6, is making about 16 million cubic feet of gas per day, and we think the A7 well could perform even better when it is tied into production late in the first quarter. Devon has a 100 percent working interest in these wells, and we have two more locations to drill.

Now, to a couple of international projects. First, in Brazil, you will remember late last year, we announced a discovery on the Devon-operated 60 percent working interest Block BM-C-8 in the offshore Campos Basin. The discovery well encountered 150 feet of pay, and a subsequent sidetrack found 200 feet of net pay with medium gravity oil. In late December, we began a third well on the block on a different shoal, but this well is still drilling.

Offshore Nigeria -- we have signed farm-outs now with two partners on Block 256; but, because the government has a right of first refusal, we won't name the partners just yet. Devon has retained a 37.5 percent working interest in the block, and we plan to spud our first exploratory well on the Tare (ph) prospect on Block 256 about the middle of this month. Tare has more than 0.5 billion barrels of gross mean commercial potential, and we have identified other prospects in the block, as well.

The final country that I'll cover is Egypt. We appear to have another good well on our East Zeit Block, which is a block that Devon operates with a 100 percent working interest, and which you might recall is a block that we drilled a very productive well on in 2004. The C3 exploration well has logged about 100 feet of oil pay, and it currently appears that this well could be a 2,000 to 4,000 barrel per day well, which we should be able to hook up pretty quickly.

Also in Egypt, the second well in our joint venture with Santos is currently drilling at about 10,300 feet, going to 17,800 feet. This well, the Rad1 (ph), is a test of the Osage prospect on the Ras Abu Darag Block. Devon is the operator, with a 50 percent working interest in this 200 million barrel prospect.

So, to sum it up, 2005 has the potential to be a very meaningful year for Devon's exploration program. While only about 13 percent of our total 2005 exploration and development budget targets high-impact projects, this gives the Company exposure to approximately 40 such opportunities.

With that, let me turn the call over to Brian Jennings to review our financial results and outlook.

I want to depart today from our traditional line item approach, and instead spend the remainder of the call focusing on the financial drivers that impacted our 2004 results and, more importantly, our 2005 outlook. In addition, I will provide you with an update on our divestiture and share repurchase initiatives. For those of you who prepare financial models, I will direct you to our press release, which provides line item detail of our 2004 results. In addition, as Vince disclosed in his opening remarks, we are filing a Form 8-K this morning that details our 2005 guidance.

Before I move into the 2004 results, I want to update you on the progress of our divestiture program. We had announced in September, at our executive briefing, our intention to divest non-core properties located in Canada, the onshore US and in the Gulf of Mexico. We had estimated at that time that the identified non-core properties would produce for the year about 34 million barrels equivalent of production. That estimate was in fact spot-on. As many of you know, the divestiture process is in full swing, with data rooms open and activity peaking. As you can imagine, there has been a high level of interest in these properties. Consequently, we currently expect our after-tax proceeds to come at high end of our forecasted range of $1 to $1.5 billion.

Looking briefly at production, as Larry discussed, we reported full-year 2004 production of 251 million barrels of oil equivalent. This result was right in line with our guidance. We achieved this target despite having 1.1 million barrels of production shut-in, in the third and fourth quarters, due to hurricane activity. In the fourth quarter, we produced a hurricane-impacted 62 million barrels of oil equivalent.

Focusing on 2005 production, we are forecasting organic production growth from our core North quarter American assets. However, in the year, we expect our international production to decline. The expected production decline will come from our Zafiro and Panyu fields. At Zafiro, our largest international producing asset, Devon's share of production is expected to be approximately 20 percent lower in the year. The expected reduction is due to normal field decline, as well as a contractual midyear reduction in Devon's share of total production. In addition, production from the Devon-operated Panyu field is also expected to be approximately 20 percent lower in 2005, as a consequence of field decline. Field production peaked at Panyu in late 2004. In total, we expect international production to decline approximately 20 percent year over year, from 35 million barrels in 2004 to about 27 million in 2005.

For the year, when you combine the organic production growth from our North American assets with the reduced international volumes, we expect to deliver in 2004 same-store production -- that is, production from our core properties excluding the properties we are divesting -- roughly equal to the 2004 level of 217 million barrels equivalent. This production profile is consistent with the guidance we provided in September.

On a reported basis, please note that our first-quarter 2005 results will benefit from the production associated with the divestiture properties. We estimate that these assets will produce around 7 million barrels in the first quarter, bringing our forecasted first-quarter production to between 59 and 61 million barrels equivalent. We remain confident in our ability to deliver 6 percent compounded annual growth in production through 2009. If current market conditions persist, we would have significant free cash flow available during that period to significantly enhance our per-share performance, through a combination of incremental capital investment, accelerated debt reduction or expanded share repurchases.

Let me now spend a brief moment looking at price realizations. As I am sure you are all aware, differentials for almost all the products we sell widened significantly in the fourth quarter. This is not new news. On top of wider differentials reducing our floating price realizations for both oil and natural gas, our oil price realizations were negatively impacted throughout the year, as a consequence of hedges we had in place in 2004. So far in 2005, oil and gas price differentials have begun to retreat somewhat from their fourth-quarter levels. We do expect differentials to continue to narrow. However, as our 8-K guidance will indicate, we are forecasting differentials on certain products to remain wider in 2005.

Our marketing and midstream division posted record performance in 2004, driven by stronger oil, gas and NGL prices. The division reported 362 million of operating margin, a 26 percent increase over our 2003 results. In early January, we reported on the very successful conclusion of the division's restructuring, with the completion of several non-core asset sales. In 2005, we are currently forecasting an operating margin of $260 to $300 million, reflecting the impact of the asset sales and lower forecasted frac spreads.

Before I move to expenses, I want to highlight the increase in other revenue we reported in 2004. Our other revenues climbed to 103 million, compared to 37 million in 2003. This increase is principally due to the recognition of a $30 million gain in the fourth quarter on the disposition of non-core midstream assets and increased interest income. In 2005, we estimate that our other revenues will climb to 260 to 270 million. This increase is driven by greater cash balances, higher expected interest rates on those cash balances and the recognition of an additional $150 million gain in the first quarter from the dispositions of our remaining non-core midstream assets.

On the expense front, the strengthening of the Canadian dollar in 2004 and 2005 is putting pressure on most of our expenses. In 2004, the exchange rate averaged 77 cents, a 7 percent increase over the 2003 average. This strengthening of the Canadian dollar accounted for approximately 2 percent of our increase in 2004 per-unit lease operating, transportation and DD&A expenses. Our 2005 exchange rate forecast assumes that the Canadian dollar will average 82 cents. Based on this forecast, the appreciating Canadian dollar will add an incremental 2 percent to our 2005 per-unit lease operating, transportation and DD&A expenses. Despite the negative impact of the Canadian exchange rate and the trend of rising industry costs, our 2004 per-unit lease operating and transportation expenses were in line with our guidance, at $5.11 per equivalent barrel. That was an 8 percent increase over 2003. For 2005, we expect our per-unit lease operating and transportation expenses for our core properties to come in between $5.32 and $5.65 per equivalent barrel. We attribute the forecasted 8 percent year-over-year unit cost increase to the impact of the stronger Canadian dollar, upward pressure on services and supplies and greater workover activity.

In 2004, our general and administrative expenses totaled 277 million, which was 10 percent less than our reported 2003 expense of 307 million. We are pleased with this reduction, as it evidences the tangible value we have captured following our 2003 merger with Ocean Energy. In the fourth quarter, our G&A expense came in at 72 million. Our fourth-quarter expense includes the one-time recognition of the $10 million commitment that Devon made to support university-level education of oil and gas-related disciplines. Even though this educational commitment is to be funded over a five-year period, accounting rules required us to recognize the entire non-cash expense in the fourth quarter.

Looking forward to 2005, we are forecasting G&A expenses to come in between $260 and $280 million. Our current forecast excludes any G&A savings that we anticipate being able to capture following our divestitures, as well as the one-time costs associated with this restructuring.

Looking briefly at taxes, 2004 income taxes, at 34 percent of our pretax earnings, were near the midpoint of our guidance range. About one-third of our total tax expense was deferred. The fourth-quarter result reflected a true-up of our expected tax rate for the full year. Looking to 2005, our income tax forecast remains the same as 2004.

Before we open up the call to Q&A, I want to spend a moment updating you on the Company's financial position and the status of the 50 million share repurchase initiative we announced in September. That share target is, of course, adjusted for our fourth-quarter 2004 2-for-1 stock split. In the fourth quarter, our cash flow before balance sheet changes totaled 1.3 billion. That's approximately 570 million greater than our total fourth-quarter cash expenditures. For the full year, our cash flow before balance sheet changes totaled a record 4.9 billion, allowing us to fully fund our 3.2 billion of total cash expenditures including dividends, while generating 1.7 billion of free cash flow.

In addition to fully funding our cash expenditures, we retired in 2004 973 million of maturing debt. In addition, we repurchased 5 million shares of our common stock at a cost of 189 million. Even with these expenditures, we concluded 2004 with 2.1 billion of cash, a year-over-year increase of over 800 million.

In 2005, we are well-positioned to conclude the balance sheet transformation we initiated in 2002. With a cash balance today of 2.4 billion, we plan to retire in 2005 an additional 932 million of maturing debt, and look forward to retiring in 2006 and 2007 an additional 1.1 billion of maturing obligations.

We expect that our share repurchase initiative will gained considerable momentum in 2005, as we bring our non-core divestiture process to a conclusion. Since the beginning of the year, we have repurchased an additional 2.5 million shares, bringing our total repurchases to 7.5 million shares as of today. In September, at the time of our repurchase announcement, we had anticipated completing the program in an 18-month period. As we gain more visibility on our divestiture outcomes, and provided that commodity prices remain steady, we would expect to accelerate the pace of our repurchases in 2005.

As Larry and John indicated, 2005 will be an exciting year for Devon. Our core North American assets continue to deliver strong production growth, high margin and great returns. Our exploration-weighted activities in the Gulf and in our international division exposes our shareholders to meaningful value creation opportunities. Our rapidly-improving financial position provides the flexibility as we look forward to expand our investments, to retire debt, to repurchase stock and to enhance our dividend.

And at this point, I'm going to turn it back to Vince to open it up to Q&A.

Operator, let's go ahead and open it up to the first question.

(OPERATOR INSTRUCTIONS). Steve Enger, Petrie Parkman.

Concerning a lower Tertiary test, would your goal be to do a fairly short-term test to try to assess porosity and permeability, or are you doing looking to do a long-term test to try to better understand reservoir limits?

Actually, the test would probably accomplish both of those, to some degree. Obviously, the length of the test will depend on the volumes that we get from the well, but we'd want to get in an assessment and a confirmation of the inflow performance of the well, moving as quickly towards determining the commercial configuration and ultimately sanctioning the project for development.

And do you have a sense for how long a test you may need to run to get that kind of info?

Not at this point, but obviously, with the equipment that is available to test, the test would probably be just a few weeks in duration.

And then, you had mentioned potential for another lower Tertiary wildcat someplace. Can you give us any additional color on where that may be, what you would like to target?

Well, as you know, in our inventory we have well in excess of 20 different prospects. There's a couple that are beginning to mature. We are looking at one that would be Aeroyale (ph), which is currently about a 100 percent Devon owned prospect in the area of Jack and St. Malo and in that general region. There are also a couple of other opportunities that we are working with on partners that we may look at near the second half of the year.

And then, just one housekeeping question. On Chocute, where do you end up, then, in terms of your working in net interest on that prospect, if it is successful?

We end up at about a 20 percent working interest for Devon. I don't have the net in front of me right now.

Just the working minus royalty?

Yes.

Ken Beer, Johnson Rice.

A quick question that you didn't touch on, but your property in Azerbaijan -- I know that is scheduled to come back to you after the Exxon payback sometime -- I think originally it was 2010. I think, because of pricing, maybe that gets moved up to 2008. I just wanted to get your thoughts or comments as to whether the 2008 is the better timetable now.

Well, actually, at prices that we are seeing now, it's more likely 2007.

That's even better.

It is better, and that will come and go as prices go, but if you look at today's prices, it will be more likely 2007. And of course, the pipeline that BP has been building is on schedule.

And if I remember, Larry, that would look to be about 50,000 or 60,000 barrels a day, just carried to your account. Correct?

Correct.

Fadel Gheit, Oppenheimer.

Two questions -- one on the thermal heavy oil projects in Canada. How sensitive are they to changes in oil and gas prices?

We have got to remember, with the thermal heavy oil projects, it's really five different variables that come into play. It's oil prices, gas prices, differentials, the cost of the (indiscernible) and the transportation of the blended supplies. So unfortunately, they all move in different directions. And while it is somewhat sensitive to oil and gas prices, it's really tempered a lot by the interaction of those five variables. So typically, when oil prices have gone up, differentials have gone up.

If you take Vince's comment earlier, or Larry's comment earlier that typically the differential has been about 30 percent, this project actually works very well with a $24 oil price and an $8 or $7.50 differential. So it isn't overly sensitive, only because these other variables move in different directions to kind of temper that from time to time.

And then, my second question is on Asia. Given the fact that the company is selling assets to the US, what do you see in Asia that makes it a core holding?

Egypt is a core holding for a couple of reasons. Number one, when you look at our goal to continue to have a risk-balanced portfolio in exploration and deliver consistent results year over year, Egypt is a little bit shorter cycle time with the positions that we have -- in particular, in the Gulf of Suez, and John mentioned the East Zeit position that we have. And then, as we're looking into the Gulf of Suez and the Ras Abu Darag area, the Osage prospect that we are currently drilling, we are seeing a little bit larger targets. John mentioned about 200 million barrels that are in a reasonable risk range for us to take a look at and bring on production. And the third piece is that we have an existing, producing infrastructure in the area that really makes this currently a core area for us on the exploratory front.

And specifically, what do you have there, expertise? You don't have, obviously, scale. Are you going to have operation? What do you have that makes you think that really this is a business that you should be in?

We do have operations there. Would also have geologic, geophysical and engineering expertise in the Gulf of Suez, and we are using that expertise in what we're actually learning and gaining in areas like East Zeit to extend that to the exploratory front where we're looking at wells like Osage in the Ras Abu Darag Field. So we feel like we have both a producing competency, a good understanding of the reservoirs we currently produce from. But we also have an exploratory competency where we think we can solve the puzzle of the Gulf of Suez to some degree, and have reasonable success to deliver good economic commercial results from the exploration program.

Jeff Hayden (ph), Pickering Partners.

Just wondering if you could give us a little more color on what you plan to do in West Africa this year, beyond the Tare prospect.

What we plan to do in West Africa --

In West Africa, we have plans -- we have talked about Block 256. Tare will be the first prospect we drill on that. We're moving a rig on there in the latter part of this month, and expect to drill the well in about 40, 50 days or so.

We also have a second well planned for that block. We have multiple prospects on that block that range from 500 to 700 million barrel -- the net mean reserve sizes. And we really are very hopeful and encouraged by what we see relative to the seismic work and the preparation work that we have done. So there's a follow-up well on 256 in addition to the well that we spoke about in the prepared remarks.

In addition to that, we are continuing to work our Block 242 in Nigeria. We plan to drill a well, I believe, in 2006 there. But we are doing the G&G work that is necessary in order to prepare us to do that. We are very encouraged by the work and the results that we are seeing there.

We also have several wells that we're going to drill down in Angola on Block 10 and Block 24. We are working through that process now, and those wells are scheduled to be drilled this year. We also have some additional work that we're doing in our projects in the Kowe block off Gabon. And that's really the principal larger wells that we have. We also have some follow-up work. As you know, we have a big position and a very profitable position in EG, relative to the Zafiro Field. And within the existing acreage, the blocks that we hold there, we also have an additional exploratory target there called Esmerelda that we will be drilling probably around the mid-year area. So quite an active year in West Africa, with some pretty high-impact projects that we're looking at.

Derek Winger (ph), Jefferies & Co.

I apologize if you have said this already, but the capital expenditure budget for this year, '05?

The 2005 E&P capital budget is -- the midpoint of the range that we provided is 2.8 billion.

And there will be detail, obviously, on the budget in the 8-K we file.

The number mentioned in the call was larger because, also, we were trying to drive towards the total drill bit capital, which includes capitalized G&A and interest expense. That brings that to about 3.1 billion.

Owen Malent (ph), Merrill Lynch.

You said that you were interested in booking reserves with more activity in the deepwater Gulf of Mexico this year. Could you give us kind of a ballpark sense in '06 of what kind of development costs you would be assuming for those types of projects, assuming one gets approved?

John (ph), it's hard to say. As you know, we're still looking at what the development plan for a prospect like that might look like. It requires the drilling of a number of wells, in order to fully develop the prospect, and also what we're still trying to determine is what the appropriate configuration is for delivery of the product, whether by pipeline, by SOP (ph) or otherwise. So it's a little bit hard to say that right now. We really need to get past this first production test to get a better feel for the kind of production that we're going to deliver and the kind of volumes that we're going to see, and then we can really make that test, or that determination.

I'd just add that in ballpark terms, we've talked about a single field development being in the range of $1 billion of capital at 8.8 (ph). Of course, we don't own 100 percent of the discoveries. And if it's a multi-field development configuration, it would be more in the $2 to $3 billion range.

But that's an exceedingly rough number.

Right.

That's fine. The next question from me -- obviously, EnCana is selling some interest in properties that you are also involved in. Is that something you will look at? Would you want more exposure to the Gulf?

Obviously, we have a very good position in the Gulf. We are really focusing on a couple of areas when we look at our exploration prospects and inventories. We're looking at the both the deepwater Miocene. We talked about the deepwater lower Tertiary. We're doing some deep shelf work. And obviously, as things come available, like the EnCana assets in the Gulf, we will have a look at those and see how they fit with our exploration portfolio going forward, and see how that can work or not work, relative to delivering those year-on-year results that we need from the exploration portfolio. So we'll certainly just have a look at it.

I might add we already, of course, have a very good position. I think we have over 600,000 net acres in the Deepwater, so we have got a very good position there, and won't need to stream idly to enter this area, because we already have an interest in a lot of the prospects that EnCana has.

Gil Yang, Smith Barney.

Have you given any thoughts to putting in some downstream upgrading facilities for your Jack project, to minimize the exposure to the differential?

This is Darryl Smette, and we certainly have given some thought to adding a downstream component to our heavy oil project, and are looking at a lot of options right now, including upgraders, pipeline facilities, et cetera. So yes, that evaluation is ongoing.

Do you think that that is something that you -- is it a question of what you put in place, or is it a question of will you put something in place?

Well, like I say, we are going through all the evaluations right now. If you look at our domestic operations, you will see that we have went more downstream over the last few years, where we have midstream assets to support our large E&P operations, and so we will probably continue to move that direction in Canada also.

I guess the other thing, too, I would just throw in there is right now, as you know, from Jackfish, we're going to be producing about 35,000 barrels a day, and we have some other smaller interests, as well. But that will become more important, particularly if we start to increase the volumes of the heavies. Our look at downstream operations will be even more important at that point in time than it is today, because we think there is actually quite a bit of capacity to do some of these things with the volumes that we are producing.

And the more you produce, the more you put pressure on the differential, ultimately. Thank you.

Forest Temple (ph), Flowline Partners (ph).

This is actually geared most towards Larry. Larry, it doesn't seem to me that the street is giving you enough credit for your Barnett Shale acreage, and I know it is a massive piece of your portfolio. Have you all considered doing anything else to try and realize that value that seems to be masked in the stock price right now?

I think the street in due course will give us full value for that. We have been somewhat cautious there, both in our reserve bookings. Our performance revisions in the Barnett Shale alone added 36 million barrels to performance revisions. So we have been cautious in our bookings. We also have wanted to drill in our non-core, in Parker and Johnson County, a really wide suite of horizontal wells to test what is there and to get some real production history before we really threw a tremendous amount of capital at those areas.

As we indicated, we are increasing the capital that we're going to spend in 2005 there. We think we'll get some growth in 2005, and we really think we will get meaningful growth out of the Barnett Shale in 2006. So we've got a lot of running room left to go. We think we're going about it in an aggressive but prudent way, and we think that will get rewarded in due course. A lot of people have talked about starting with small positions and growing. The Barnett Shale is producing about a Tcf a day, and we are producing over half of that. And at the end of the day, the goal is not just to drill wells, the goal is to drill wells and get them onstream. And we are being very efficient at that. We've got our own marketing and midstream division that is getting those wells hooked up in a matter of days after we get the well drilled. So we are really maximizing our value there, and we think we will get full value as the strength of those assets becomes clear.

It's a tremendous asset. I'll be glad that -- you guys are doing a great job with it. I just hope the street finally starts giving you some credit.

Paul Case (ph), Lehman Brothers.

Just two quick questions. First, can you give us some regional breakdown for the reserve adds that you are targeting for the current year, the 330 to 380?

That's not in our 8-K, is it?

No, we have not yet provided that level of detail, and I don't have those numbers at my fingertips. I will say that we would expect similar performance in our North American onshore and then an incremental performance in our Gulf of Mexico.

So it's going to be primarily driven by the onshore North American market, again?

Yes. If you look at it, onshore, the areas where we drilled and added reserves in 2004 were the same areas they were in 2003 and the same areas they will be in 2005. It's the Barnett Shale, it's adding reserves in the Permian Basin, Carthage area, Deep Basin Foothills and Canada -- it's the same areas that we have been growing for sometime. One of the reasons that we broke out US onshore and US offshore is so that you really could see the strength of the core assets we have in US onshore. So we think we'll have those additions that will -- while they may shift a little bit from those areas, the areas that we talked about earlier in the conference call are most likely going to be the same areas you are going to hear from next year. We've got some new areas that we're looking at like the Bossier play, where we have a large mineral acreage position that we built up over time, quietly. But the new adds that will come in 2005 will -- we do expect to add for the first time Jackfish, our heavy oil project in Canada, which we have been forecasting we would add in 2005 all of last year. And we're hopeful -- it's hard to say with the same level of certainty that we will start adding reserves from at least one of our deep wells.

But you are assuming some improvement directionally in your finding costs and reserve replacement offshore and internationally? Because when you break that out this past year, obviously, it compares unfavorably to the onshore.

Absolutely. And it is because the projects in the Gulf of Mexico and international, unlike the ones onshore, have been more longer-weighted. We have known that, and we have intentionally done that, because we saw the results and we thought we could produce really meaningful shareholder results by the drilling we're doing in the Miocene and the lower Tertiary. And so far, it's looking very good. And obviously, when you're spending that kind of money upfront, you are not going to get good results, in terms of a short-term one-year number or two-year number, because they are longer-term projects. But we think -- and a little longer-term in our activity in Brazil and West Africa. But all those projects are looking very good, and we see no reason to change now.

And just a second follow-up question. In terms of the guidance that you gave for '04, in terms of your operating performance -- and, I guess, '05, too -- is the understanding with the agencies that that is all sources? Or is that just a pure drill bit number? Because if you include all the revisions, including the negative price-related ones, that would put you just shy of some of these ranges, whereas, if you back them out, obviously, that would put you north of them.

When you say the agencies, you mean the debt rating agencies?

Yes, the rating agencies.

I'm sure the rating agencies will look at our press release. I'm sure they are listening in on the call to the. As you know, Moody's moved us in the fall to a stable outlook. But these results I would characterize as very favorable and, of course, delivering on the plan that we laid out in September.

And I think that the rating agencies, as well as everyone else, can see that the price revisions with regard to heavy oil projects come and go. There will be brief moments in history where those projects do result in reserve write-offs, but if you look at any long-term history in differentials, those reserves will pop back on the books this year.

We have already gone five minutes over. We'll take one more question, and then we'll end the call.

Robert Christensen, Buckingham Research.

This production test of the lower Tertiary -- what kind of permits are required, and what kind of physical assets are required to do a test? And my guess would -- it would have to come sort of in the spring or summer, maybe when the weather and sea conditions are right. So is it sort of earlier rather than later in the year? Is it first half, do you think?

I think there is some specific equipment requirements for those tests. We're working with the folks that may be involved in these tests, and we feel confident that the equipment issue can be resolved favorably. Don't think that it would be in the first half of year, probably more in the second half of the year, as we would do it. And I don't anticipate or know of any problems or issues centered around permitting.

But what kind of equipment are we talking about? I'm just unfamiliar with what -- is it a tanker, some mooring buoy? You must have to make some federal permits.

It would be a combination of a drilling rig, equipped with a production barge, where you could take the production from the test and store it in the barge.

Well, that concludes our call. As we have said in the past, anyone who has further questions, we will be delighted to answer them during the coming days. We're very excited with our 2004 results. They came in better than we forecasted all year long, and we are looking forward to 2005 being even better. Thank you very much.