德文能源 (DVN) 2002 Q4 法說會逐字稿

Good morning, I will be your conference call facilitator. At this time, I would like to welcome everyone to the Devon Energy Corporation fourth quarter earnings release conference call. All lines are on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. If you would like to ask a question during this time, simply press star, then the Number 1 on your telephone keypad. If you would like to withdraw your question, press star, then the Number 2 on your telephone keypad. On behalf of Devon's management, I will remind you that any statements the company makes not based on historical facts are forward-looking statements. Actual results may differ materially. Devon's filed a form 8 K on December 10, 2002, including the company's estimates for the year 2003. The form 8 K also includes discussions of factors that could cause Devon's actual results to differ from its estimates. Devon's management encourages you to review the estimate and risk statements in their public document. This call will be available for replay beginning at 12:30 p.m. eastern time through today, through 11:59 p.m. eastern time on February 13, 2003. The conference ID number for the replay is: 7517954. Again, the conference ID number for the replay is 7517954. The number to dial for the replay is: 1-800-642-1687 or 706-645-9291. At this time, I would like to turn the call over to Mr. Larry Nichols. Chairman, President and CEO. Thank you, Mr. Nichols, you may begin your conference.

Thank you. Good morning and thanks for joining us. The purpose of the call of course is to spend an hour with you discussing our 2002 results. As usual, I'll make a few general observations on the highlights as I see it and turn it over to Vince White, our Vice President of communications and investor relations for a more detailed analysis. After that, you'll have an opportunity to ask questions. If you don't get your questions in, by all means call us later because our goal is to answer each and everyone's question.

This year, year 2002 was a very active and a very successful one for Devon. We had a very strong finish to 2002, fourth quarter production came in better than expected. And we beat consensus estimates for both earnings and cash flows and we beat them by wide margins, as you'll learn later. For the full year, we set all time records for total production, total revenues, and most importantly, production per share. Now, we replaced 278% of our production at a finding and development cost of $7.18 per barrel. We also upgraded our asset base with the Mitchell acquisition and the disposition of more than a billion dollars of noncore properties.

As we told at the beginning of the street, we reduced long-term debt by $1.3 billion during the last nine months of the year, and ended up the year with almost $300 million in cash on hand. We had funded our entire exploration and development budget with cash flow from operations. With that capital, we achieved the following: First, we increased production from retained properties by 2.3%. And secondly, we successfully invested over $300 million in longer term growth projects. As we look forward to 2003, we again will fund a robust drilling budget with cash flow from operations. We again plan on delivering organic growth from our high quality property base and will again invest even more in projects designed to fuel our long-term growth strategy.

We also will continue to focus on minimizing our cost structure. If commodity prices continue to favor us, which we think they will, we will generate significant excess cash flows that we will target for further debt reduction during 2003. All in all, we're very pleased with where we have Devon positioned, with acquisitions of Mitchell and Anderson, a year ago, a year and a quarter ago, we had substantially exposed our shareholders and our company to the robust gas markets that we're enjoying now and that we think we will continue to enjoy in the future. At this point, I'll turn the call over to Vince White. Vince?

Thanks, Larry. Before we get started, I just wanted to remind you that today's transmission, the press release is 13 pages, if you received an incomplete copy or did not get a copy, you can download that from our website, that address is www.devonenergy.com. We've got a lot of ground to cover today.

I've organized my comments into three main topics. First I'm going to cover the financial results and the drivers behind them. Then I'm going to provide some color for the year-end reserves reconciliation and costs incurred and talk about finding costs. And finally, I'll end my remarks with a fourth quarter operating highlight update.

Starting with the financial results, I want to remind you that we completed our Mitchell acquisition in late January of 2002. As a result, the full-year results reflect a little over 11 months of operations, including the Mitchell assets, and the full year for everything else. I also want to remind you that we exited our operations in Indonesia, Argentina and Egypt or discontinued the operations and that generally accepted accounting principles require us to reclassify all the production volumes, revenues, expenses, reserves, capital expenditures, all those items related to those countries that we have discontinued operations in, have been excluded from all of the data provided.

The revenue and expense items are collapsed into one line item on the income statement. I'm going to focus my comments on the revised data which excludes the discontinued operations. Looking first at production, company-wide production of oil, gas and NGLs was 188 million equivalent barrels in 2002. That is a 50% increase or 62 million-barrel increase over the full year 2001. The big driver, of course, were the two acquisitions, the Anderson acquisition which we made in late 2001 and the Mitchell acquisition which we closed in early 2002. Looking at fourth quarter production, in 2002 that came in at 45.5 million equivalent barrels, that is an 11% increase over the fourth quarter of 2001. On a sequential quarter basis, our fourth quarter 2002 production was up 7/10 of a million barrels, 700,000 barrels, that's a 2% increase over reported third quarter production. However, when you back out the production from the properties that we sold in the third and fourth quarters, the sequential comparison is more favorable. The fourth quarter production from the retained properties was 45.2 million equivalent barrels, that compared to 43.9 equivalent barrels in the third quarter. So on a same-store sales basis, if you will, production was up about 3% in the fourth quarter of this year. Full-year 2002 production from the retained properties, again, I'm looking at the same-store sales figure but for the full year, that totaled 176.3 million equivalent barrels, but to make the same-store sales comparison, you have to add in production for Mitchell for the first 24 days of 2002. That's the period prior to the close of the acquisition. When you do that, you find we had 2002 pro forma production from retained properties of 178.6 million equivalent barrels. That compares to 2001 production for Devon, Mitchell and Anderson combined, adjusted for property sales of 174.6 million equivalent barrels, or a 2.3% year-over-year increase, that is organic growth from retained properties.

Moving now to prices, oil, gas and NGL prices all climbed sharply in the fourth quarter. Devon's fourth quarter average realized oil prices were up 32% over the fourth quarter of 2001. Our realized gas prices were up 33% and our realized NGLs prices were up 26% over the third quarter of -- no, over the fourth quarter of 2001. Floating price realizations, that is what we got on the volumes that weren't impacted by hedges, collars, swaps, fixed price sale agreement, those that are truly market sensitive, these came in pretty much in line with the guidance that we provided, with just a couple of exceptions I'm going to cover. First, U.S. floating gas prices, realized prices, averaged 338 per MCF in the fourth quarter, 61 cents under the NIMEX Henry Hub price. Even though that's within the range of our guidance, it's at the wide end that we provided and we indicated last quarter that we expected U.S. gas price differentials to narrow as we move into the winter months and I wanted to point out that has failed to materialize so far. Warmer than normal temperatures throughout the western U.S. combined with cool weather in the east and midwestern U.S. resulted in a continuation of wide differentials for Rockies gas and in addition, most areas in the U.S. that don't have direct access to Henry Hub have traded at wider than normal differentials over the last 6 to 9 months. Unlike in the U.S., Canadian gas price differentials did improve significantly during the fourth quarter. Our fourth quarter floating gas price realizations in Canada averaged 350 MCF, that was 49 cents under NIMEX. That compares to a 90-cent discount to NIMEX for our Canadian gas during the third quarter of 2002. So that closed up significantly during the fourth quarter. While the Canadian gas price differentials improved, Canadian oil price differentials widened. Our fourth quarter floating oil price realization in Canada was $21.74 a barrel, that was $6.46 under NIMEX. That compared to about $4.66 below NIMEX for the full year 2002. You can see they widened significantly in the fourth quarter. Differentials for sour and heavy crudes widened due to a seasonal decline and asphalt demand and also because there were incremental heavy and sour crude supplies coming on the market late in 2002. In early 2003, we've seen those differentials start to close. They've closed about $1.50 in January. We tribute this to the disruption in oil production from Venezuela, most of that is heavier sour.

Before we move to the expense discussion, I want to touch on the marketing and midstream results. Fourth quarter marketing and midstream revenues totaled $307 million. When you back out the related costs and expenses you'll find we had margins in our marketing and midstream of $58 million. That's about $4 million better than expectations. And for the full year marketing margins came in at $191 million, or $22 million over the midpoint of our forecast. Moving now to expenses, most of the expense items came in the fourth quarter in line with our guidance.

I'm going to touch on just a few items that nonrecurring or unusual variances in the fourth quarter. First, general and administrative expenses came in at $68 million for the fourth quarter. I just want to point out that that includes a one-time charge of $13 million for the abandonment of office space. We got that space in conjunction with our 2000 merger with Santa Fe. At the time that we merged with Santa Fe, we thought we'd be able to sublease the space, when we moved out the employees and moved them into our Houston offices. But with the fallout of the Enron collapse, the Houston real estate market softened. In the fourth quarter we're recognizing a loss we expect to realize on the office space in the future. Also in G&A in the fourth quarter, we had a catchup item of about $3 million. This was due to a change in an actuarial assumption on a retiree health benefit plan. When you back out the two items, you'll find that fourth quarter G&A was $52 million, about in line with exceptions.

The next item I want to cover is a line item entitled, "Impairment of ChevronTexaco Common Stock." During the fourth quarter we took a noncash charge to earnings of $205 million pretax, or $128 million after tax. Let me give you a little history on our ownership of ChevronTexaco shares. We acquired 7.1 million shares of that stock when we acquired PennzEnergy in August of 1999. Those are being held with an exchange agent for possible exchange for 760 million of exchangeable debentures that we assumed also in the PennzEnergy merger. We have a liability of a bond that matures in late 2008, which is -- these shares are being held to be exchanged into those debt exchangeable securities. When we acquired those shares, they were recorded at their fair market value on the closing date of the PennzEnergy merger. From that point to the end of the third quarter of 2002, reductions in the market value of those shares were made as an adjustment to Devon's stockholder equity on our balance sheet. Accounting rules deem that's the proper way to account for for fluctuations in ChevronTexaco stock price as long as we determine the decline to be temporary. However, since the middle of 2002, the stock is -- ChevronTexaco has continued to decline significantly and as a result, we have now determined the price decline to be other than temporary, as defined by accounting rules. As a result, the adjustments to equity that we've been recording through the balance sheet all along must now be recognized in the P&L. That $205 million charge we're taking is cash neutral. Importantly, as we have been recognizing the price decline by reducing equity, the charge will have no effect on our equity currently. Going forward, should the price recover for ChevronTexaco stock, we will not recognize any benefit in the P&L. However, if it continues to decline and the additional declines have been determined to be other than temporary, we may be required to take additional charges in future periods.

The next expense item I want to cover is income taxes. The fourth quarter tax provisions true up the full-year taxes based on our most current estimates. And several facts came to light during the fourth quarter that have reduced our full-year tax expense. One was the recognition of the loss on the ChevronTexaco stock that resulted in a $77 million deferred tax benefit. Also, there was a statutory rate change in Canada, a reduction in the statutory rate, that helped reduce taxes. If you back out the tax effects of the special items and property sales, you'll find we had a current tax benefit of $16 million, and a deferred tax expense of $174 million for the full year 2002. That gives us an adjusted tax expense of $158 million, or about 22% of adjusted or clean pretax earnings. For those of you that keep models on Devon, we provided detail on this in the press release so that you can get the fourth quarter clean number tax effects in your model correctly correctly. Looking to 2003, we expect our total income tax expense to be approximately 30% of pretax earnings. With about one-third of that current and two-thirds deferred. It's probably worth noting that our income tax estimates are based on a myriad of assumptions and they are extremely difficult to forecast and will continue to be difficult to forecast. When you take the revenues, back out all the normal expenses, you'll find we had fourth quarter earnings before special items, this is the number that's comparable to the analysts' consensus estimates, those earnings were $232 million, or $1.42 per diluted common share, that's about 29 cents above the first call consensus. That level of earnings translates to cash flow of about $630 million for the quarter, or $3.87 per diluted share, compare to consensus cash flow estimate of $3.18 per share.

For the full year, earnings excluding the impact of special items and property sales, total $549 million, or $3.41 per diluted share, that yields adjusted cash flow for 2002 of a little over $1.9 billion, or $12.02 per diluted share. The positive surprise not quarter in the year was driven by better than expected fourth quarter production, better than expected midstream margins, and most significantly, lower than expected income taxes.

I'll move now to the discussion of the reserves and finding and development costs. Before we get into the changes of the year, I'll remind you again that the reserve reconciliation that we've provided today, that's on page 12 of the news release, that excludes from both beginning changes and ending balances the operations that been reclassified as discontinued operations. And those are the operations in Indonesia, Argentina and Egypt. I'm going to focus on the data that's provided, the data that excludes those countries or operations in those countries. On the revised basis, we entered 2002 with total crude reserves of 1.47 billion equivalent barrels. During January we closed the Mitchell acquisition, as I mentioned earlier, that added just over 400 million equivalent barrels of crude reserves. Discoveries and extensions added another 142 million equivalent barrels. Those additions were reduced by 23 million barrels of negative revisions. The majority of those negative revisions were due to price. Remember that under international production sharing agreements, higher prices result in an earlier back-in by the government and, therefore, reduce the estimated reserves that are retained by the producer. For an example, in Azerbaijan alone, we lost over 20 million barrels due to higher year end oil prices. In Canada, higher oil and gas prices reduced reserves, due to the sliding scale royalty payments we make to the crown or Canadian government. In any case, should prices go down in the future, we will recover the reserves in both places. When you sum up the acquisitions, discoveries, and extensions and net out the revisions, you'll see we booked total additions for the year of 524 million equivalent barrels, that's 278% of our 2002 production, strong reserve replacement. These additions were partially offset by sales of noncore properties in the U.S. and Canada, those were about 200 million. Again, I remind you that the 145 million barrels of reserves that we sold internationally are excluded from this analysis. Taking all the additions, backing out the reported divestitures, the revisions and the production for the year, we ended 2002 with 1.61 billion equivalent barrels of crude reserves.

Moving now to finding and development costs, cost incurred for the year for acquisitions, exploration, development, capitalized G&A, all these costs totaled about $3.76 billion. That gives us an all-sources finding and development cost of $7.18 per equivalent barrel for the year. For a company like Devon, we've completed a series of large-scale acquisitions. They've included significant quantities of crude, undeveloped reserves. The all sources number is really the only meaningful measure of finding and development costs. The reason for that is when you try to compare our F & D from acquisitions to that from drilling, the comparison is distorted because the cost of developing the undeveloped reserves of the acquired companies, goes against our drill bit finding and development costs. Because the costs go into our drill bit calculation, but the reserves go into acquisitions calculation, both numbers are misstated. Drill bit F & D is overstated, and acquisitions F & D is understated. Nonetheless, many will undoubtedly calculate a drill bit finding and development cost for us so let's look at that number. Extensions, discoveries and revisions for the year including the negative price revisions that I mentioned earlier totaled 119 million equivalent barrels. Our capital expenditures excluding acquisitions were a little under $1.6 billion, that's $1 billion, 587 million to be exact. That gives us a drill bit only finding and development costs reported for 2002 of $13.35 per barrel. However, the portion of 2002 capex related to the development of crude, undeveloped reserves was about $480 million, if you back that number out from the cost, you'll find that our drill bit F & D comes in at about 9.30 a barrel. While that number is higher than we hope to see over the long run, it's not out of line with recent industry results.

Regardless of which of the numbers you focus on, we accomplished a number of things in 2002 with our capital spending that are not obvious from a quantitative analysis, I want to hit on those briefly. First, as we -- as Larry mentioned earlier, we invested over $300 million on projects that were by their very nature, not expected to impact reserve bookings for 2002. These are long-cycle time projects, examples are exploration in the Mackenzie Delta, exploration in the deepwater Gulf of Mexico, and exploration offshore West Africa. Not only did we invest here in 2002, we did it successfully. Three of the wells in the high impact wells were successful. As a result of those wells, we expect to book at least 100 million barrels of reserves over future years. Looking to 2003, as we laid out in our recent meetings in New York and San Francisco, we expect to spend about $370 million on similar long-term projects during 2003. Again, these will have no near-term impact on reserve additions. As a result, we expect our drill bit F & D to come in between $10 and $11 per barrel in 2003. In future years, as this pipeline of long cycle time projects that we're building begins to show up in reserve bookings, we think the drill bit F & D and drill bit reserves replacement will both improve.

Another thing that we accomplished in 2002 with our capital budget was reducing our inventory of proved undeveloped reserves. As I mentioned earlier, one of the factors that drove up the drill bit F & D in '02 was the capital we used in developing crude reserves, undeveloped reserves that we acquired. Following the Mitchell acquisition, about 36% of Devon's company-wide reserves were classified as proved undeveloped. By the end of the year, we reduced that to 27% of total reserves. That compares to a peer group average of more than 30% of total reserves classified as crude undeveloped. As we work off this inventory of reserves and reduce our crude, undeveloped reserves to the conservative levels that Devon has typically carried in the past, these costs will become less and less of a factor in our reported F & D.

Finally, we significantly upgraded our asset base during 2002, both by acquiring Mitchell's high quality Barnett Shale reserves and their midstream assets and by selling marginal properties in Indonesia, Argentina, Egypt, Canada and the U.S., we have enhanced the company's operating margins and our long term growth process. At the same time, we significantly reduced the overall political risk that's associated with our property portfolio.

Moving now to fourth quarter operating highlights, I'm going to move through this quickly. At the end of the year, that's the end of 2002, we had 94 rigs running company wide. That is up from 55 rigs running at the end of the third quarter. That increase really reflects the high level of activity that's typical for us in Canada during the winter drilling season. Total capital for exploration and development in the fourth quarter was about $355 million, that brings the full year exploration and development capital up to $1.5 billion. With that, we drilled a total of 1,685 wells during the year. 1,599 of those were successful. Overall success rate was 95%. Of those wells, 276 were classified as exploration wells, 217 of the 276 were successful. 1409 were classified as exploitation and development wells. Of those, 1382 were successful.

Moving now to the fourth quarter highlights, looking first at our largest gas producing area, that of course is the Barnett Shale in north Texas, we continued an active drilling program throughout the fourth quarter. We drilled 84 Barnett wells, we brought 82 under production and we had 31 wells awaiting connection to the sales line at the end of the year. We also performed 46 refracs of older wells during the fourth quarter, driving our net production up, it averaged about 470 million cubic feet equivalent per day during the fourth quarter. That's up from less than 450 million cubic feet per day during the third quarter. Looking at a snapshot yesterday, we were producing about 500 million per day equivalent out of the Barnett Shale. For the full year, 2002, we invested $305 million in the Barnett Shale drilling, we drilled 385 wells. This year, that is 2003, we have an even more robust plan. We expect to spend about $350 million and drill over 450 new wells.

One caveat here, the application of horizontal drilling, I'm about to talk about this more, may reduce the total number of wells that we need to drill in the Barnett Shale.