馬拉松石油 (MRO) 2006 Q2 法說會逐字稿

Good day, everyone, and welcome to this Marathon Oil Corporation second quarter 2006 earnings conference call. Today's call is being recorded.

For opening remarks and introductions, I would like the turn the call over to Mr. Howard Thill, Director of Investor Relations. Please go ahead, sir.

Thank you and welcome to Marathon Oil Corporation's second quarter 2006 earnings webcast and teleconference.

As a reminder for telephone participants you can find the synchronized slides that accompany this call on our Web site, marathon.com.

With us on the call today are Clarence Cazalot, President and CEO, Janet Clark, Senior Vice President and CFO, Phil Behrman, Senior Vice President Worldwide Exploration, Steven Hinchman, Senior Vice President Worldwide Production, Gary Heminger, Marathon Executive VP and President of our Refining, Marketing and Transportation Organization and Gary Peiffer, Senior Vice President of Finance and Commercial Services for our downstream organization. Also joining us today is Dave Roberts who started with Marathon June 1st as Senior Vice President of Business Development.

Slide 2 contains the forward-looking statement and other information related to this presentation. Our remarks and answers to questions today will contain certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995 Marathon Oil Corporation has included in its Annual Report on Form 10-K for the year ended December 31, 2005 and subsequent Forms 10-Q and 8-K cautionary language identifying important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

As we discussed last quarter, our method of accounting for income taxes can have a significant impact on reported earnings, particularly as it relates to the sale of our Libyan production. Annually we estimate our income tax provision and calculate an effective tax rate for the year by aggregating income tax arising from all jurisdictions or countries where we operate.

For quarterly reporting the income tax provision for the quarter is determined by applying this estimated annual effective tax rate to the quarterly pre-tax earnings. Primarily because of the Libyan tax rate exceeds 90%, our corporate effective tax rate for 2006 is estimated to be 46 to 48% while the effective tax rate for the E&P segment was 52% in the second quarter.

In the first quarter of this year we were underlifted in Libya by nearly 2 million barrels. We made up most of this Libyan underlift in the second quarter selling 5.9 million barrels, or about 3.7 million barrels more than we sold in the first quarter.

Therefore, based on the E&P segment's effective tax rate, the increase in the second quarter net income versus the first quarter is estimated at approximately 135 to $140 million. Put another way, second quarter net income was approximately $70 million higher than it would have been without the makeup of the underlift from the first quarter.

Turning to Slide 3, net income for the second quarter was $1.75 billion versus $673 million in the second quarter 2005. Net income adjusted for special items, which for the second quarter of 2006 excludes the $243 million after-tax gain on the sale of the Russian businesses as well as a $10 million after-tax loss on the impact of the U.K., long-term natural gas contracts was just over $1.5 billion.

Moving to Slide 4, the substantial increase in net income adjusted for special items year-over-year was driven by four major factors: a positive price variance and a positive volume variance both in the upstream segment, overall improvement in the downstream business, and the largest single factor owning 100% of our downstream operations during the quarter just closed versus 62% in the second quarter last year. These positive factors were significantly offset by almost $900 million in higher income tax.

Moving to Slide 5, the increase in adjusted net income for the first quarter 2006 was largely a result of increased earnings in the RM&T segment along with higher sales volumes and price realizations from the upstream business. Again, notably offset by higher income tax.

A reconciliation of net income adjusted for special items to net income is included on Slide 3. Please refer to Slide 2 for a discussion of the use of this non-GAAP measure.

Moving to Slide 6, second quarter per share net income adjusted for special items on a fully diluted basis was $4.16, a 107% increase from the first quarter of 2006. There were approximately 364 million weighted average shares outstanding during the quarter on a fully diluted basis.

Year-to-date through the second quarter we repurchased approximately 7.3 million shares at a cost of $554 million. Our $2 billion share repurchase program has been accelerated and we now anticipate the repurchase of around $1.5 billion in common stock by year-end with the remainder to be repurchased in 2007.

At the current share price in the high 80's to low 90's, we would expect to repurchase around 5.5 million shares during the third quarter which would reduce the weighted average fully diluted share count to approximately 360 million for the third quarter.

As shown on Slide 7 the upstream segment income increased $194 million over the first quarter results largely a result of higher liquid sales volumes and higher realized prices partially offset by lower natural gas volumes and prices and higher income tax. The higher liquid sales volumes were mainly attributable to the substantial makeup of the almost 4 million barrel underlift we had at the end of the first quarter in Libya, the United Kingdom and Equatorial Guinea.

The lower gas sales were related mainly to lower seasonal sales in Alaska and Europe coupled with lower gas volumes in Equatorial Guinea associated with the planned turnaround of the AMPCO methanol plant.

The Russian businesses are now accounted for as a discontinued operation and therefore do not appear in the upstream segment results. Production available for sale excluding the discontinued Russian operations averaged 253,000 barrels of oil equivalent, or BOE per day, a decrease of 36,000 BOE per day from the first quarter primarily a result of the previously discussed lower gas sales.

During the third and fourth quarters we expect to produce and lift approximately 2.8 million barrels in Libya that were not included in our previous Libyan production guidance of 40 to 45,000 barrels per day for the year 2006. These are barrels owed to our account upon our return to Libya.

The lifting of these barrels will have a significant positive impact on our reported earnings primarily because of the effect on the mix of pretax income between higher tax jurisdictions and lower tax jurisdictions. Including the Libyan barrels just discussed, we anticipate production available for sale for the year to average between 350,000 and 370,000 BOE per day.

For the third quarter we expect production available for sale to average between 340,000 and 360,000 BOE per day. Again, actual sales could be significantly different than these ranges depending largely on the timing of international crude lifting.

Moving to Slide 8, domestic upstream income of $243 million was flat with the first quarter. Domestic liquid realizations increased $10.50 per barrel, or $3.26 more than the increase in the NYMEX prompt WTI largely a result of narrowed quality differentials related principally to our Wyoming crude oil production.

U.S. natural gas realizations decreased $1.31 per million cubic feet, or MCF. Prices for our lower-48 production decreased $1.89 per MCF sequentially compared to a $2.21 per MCF decrease in the Henry Hub first of month index. Sales volumes were lower by approximately 8,000 BOE per day largely as a result of a seasonality of Alaskan gas sales.

As shown on Slide 9, domestic expiration expense was $13 million higher. This was primarily a result of the Gulf of Mexico Deep Shelf Abbott well being expensed as a dry well.

DD&A was lower as a result of the $20 million impairment taken in the first quarter related to the watering out of Camden Hills in the Gulf of Mexico.

Turning to Slide 10, domestic upstream expense excluding expiration expense was $1.36 per BOE lower than the first quarter primarily as a result of the impact of the previously mentioned Camden Hills impairment.

Moving to Slide 11, domestic upstream income per BOE increased $0.45 quarter-over-quarter, largely a result of the previously discussed higher crude realizations and lower costs partially offset by lower natural gas volumes and realizations.

Moving to the international upstream and Slide 12, international income increased $196 million to $416 million. This is mainly due to the increase in liquid sales volumes particularly as it relates to Libya and higher prices partially offset by lower natural gas volumes and prices as well as much higher income tax. Slide 13 shows the impact of these price and volume variances along with the offsetting higher income tax on our international income.

As shown on Slide 14, total international upstream liquid sales volumes increased approximately 78%, largely a result of the previously discussed makeup in our first quarter underlift position. While natural gas sales decreased approximately 36% primarily due to seasonality in the European market and the lower Equatorial Guinea gas sales due to the previously mentioned plant turnaround at the AMPCO methanol plant.

International upstream expense, excluding expiration expense, decreased by almost $2 per BOE compared to the first quarter. This is largely a result of the production mix from the increase in liftings as well as changing the Kinsale Head Field in Ireland from withdrawal to injection operations.

Slide 15 shows the international upstream income increased by over $6 per BOE, largely a result of the higher realized prices and lower per barrel operating costs and expiration expense partially offset by higher income tax.

Now moving to our downstream business and Slide 16, RM&T's second quarter segment income totaled $917 million compared to $316 million in the same quarter last year. Because of the seasonality in the downstream business, I will compare the second quarter 2006 results against the same quarter in 2005.

The most significant factor contributing to downstream's improved results was owning 100% of this business during 2006 versus 62% during the second quarter of 2005. A significant increase in crack spreads compared to the same quarter in 2005 also contributed significantly to the improved results.

The WTI 6321 crack spread, which provides the indicated value spread between six barrels of WTI crude and three barrels of gasoline, two barrels of low sulfur fuel oil and one barrel of 3% Number 6 fuel oil better approximates our downstream production slate than the traditional WTI 6321 crack spread. The WTI 6321 crack spread improved substantially averaging $12.49 per barrel in the second quarter compared to $6.24 per barrel in the same quarter last year based on an average of two-thirds Chicago and one-third U.S. Gulf Coast spreads.

Because of these exceptionally strong crack spreads and the solid operating performance of our refineries last quarter, we processed about 5% more total inputs and realized higher prices on our other volumetric gains last quarter compared to the same quarter last year further improving our results.

Our total refined product sales value realizations increased more than the spot market prices included in the WTI 6321 metric resulting in a positive financial benefit versus the value change indicated by the refined product prices included in the WTI 6321 metric. Also, the crude oil markets were in [cantango] about $1.68 per barrel on average during the June 2006 quarter versus averaging $1.28 per barrel during the same quarter last year which positively benefited our cost of revenues versus the change in the price of WTI quarter-to-quarter.

These positive factors were partially offset by higher costs compared to the same quarter last year primarily due to higher depreciation expense, employee related costs, variable manufacturing costs, and terminaling and transportation expense. In addition, our cost of revenues was also relatively higher than the change in WTI prices versus the same quarter last year primarily due to the effects of rising prices.

Finally, primarily due to the increase in the price of crude oil marking to market all of our derivatives had a negative quarter-to-quarter effect, and we also recorded a negative crude oil in transit effect of about $43 million this quarter versus about a negative $19 million in the same quarter last year.

As shown on Slide 17, gasoline and distillate sales at Speedway SuperAmerica, or SSA, were down 6 million gallons quarter-over-quarter, or less than 1%. Same store gasoline sales volumes were down 1.8% primarily due to the strong performance in the second quarter 2005 and the fact that SSA's retail gasoline price averaged $2.72 per gallon this past quarter compared to $2.06 per gallon in the same quarter last year.

SSA's merchandise sales on a same store basis increased 8.7% compared to the second quarter 2005. SSA's gross margin for gasoline and distillate was $0.1019 per gallon which compared to $0.1211 per gallon realized in the same period last year.

As I stated earlier, our refineries ran very well last quarter averaging 1.038 million barrels per day of crude oil throughput and 1.245 million barrels per day of total throughputs, which are both record volumes processed for a quarter. These record performances were achieved in a quarter when we were also completing our ultra-low sulfur diesel modifications that were operational by the June 1, 2006 deadline.

Slide 18 provides a summary of segment data along with the reconciliation to net income. I will not go through this other than to point out that the Integrated Gas segment income was $17 million during the second quarter 2006 compared to $8 million in the first quarter 2006. This increase was largely a function of an effective tax rate adjustment catch-up and lower LNG and gas technology expenses.

Unallocated administrative expense was slightly up at $99 million, chiefly a result of costs related to debt disaster preparedness programs while net interest and financing costs actually turned to a positive $9 million for the quarter due to higher interest rates, higher cash balances, capitalized interest and foreign exchange gains.

Slide 19 is a new slide which includes select preliminary balance sheet and cash flow data. Due to increased cash balances, cash adjusted debt went down by $1.7 billion during the second quarter to $700 million, while the cash adjusted debt to capital ratio at June 30, 2006 fell to approximately 5%. As a reminder, the cash adjusted debt balance includes approximately $530 million of debt serviced by U.S. Steel.

Year-to-date preliminary cash flow from operations was approximately $2.2 billion, while preliminary cash flow from operations before working capital changes was approximately $2.9 billion.

Slide 20 provides information from prior periods as well as guidance for the third quarter and full year 2006.

With that, I will now turn the call over to Steve Hinchman who will make a few comments about our upstream business.

As Howard has already discussed, our production outlook for 2006 excluding Russia, is expected to fall within the range of 350,000 to 370,000 barrels of oil equivalent per day in line with our prior guidance. The range is primarily around weather-related downtime in the Gulf of Mexico.

Looking ahead, we estimate 2007 will range between 405,000 to 450,000 barrels of oil equivalent per day, and 2008 between 440,000 to 490,000 barrels of oil equivalent per day, again in line with prior guidance when you exclude Russia. The production growth in this timeframe is driven largely by major development projects including Alpine in Norway, Neptune in the Gulf of Mexico and the Equatorial Guinea LNG Train 1 project.

These projects continue to progress according to plan. The range or the volatility in the production forecast for 2007 and 2008 is primarily around the exact timing of first production to these major developments.

We've entered into two new resource plays in the U.S., the Bakken Shale in North Dakota and the Piceance Basin in Colorado. Through a legacy position in a number of land acquisitions we've accumulated a 200,000-acre position in the Bakken Shale, one of largest acreage positions in this active play.

We have drilled our first operated well and are currently drilling our second. The first well came on at over 300 barrels of oil per day without stimulation and the second well is experiencing strong oil shows while drilling.

We're presently operating two drilling rigs and we will add five new build rigs in the first half of 2007. We expect to ramp-up production to over 20,000 barrels of oil equivalent per day by 2012 and have resource potential of 100 million barrels of oil equivalent based on 300 drill locations.

In addition, we just completed a land acquisition in Piceance Basin in Colorado. We've identified 700 well locations located adjacent to existing production from the Williams Fork formation in the Grand Valley Field.

We're in the process of acquiring rigs with plans to at least bring two new build rigs in in 2007 and add two more rigs in 2008. First production is expected in late 2007. Potential resources are estimated to be 900 BCF with gas rates reaching 180 million standard cubic feet per day by 2014.

The Bakken Shale and the Piceance Basins provide Marathon with low risk reserve additions and production growth that by 2009 will more than replace the production sold in Russia.

I'll now turn it over to Gary Heminger for a few comments on downstream.

Thank you, Steve, and I'm just going to cover a couple of our big projects.

First of all, on the ultra-low sulfur diesel front, as Howard mentioned in his remarks, our expected investment in ultra-low sulfur diesel is going to be $900 million, and we now project that cost to be approximately $875 million, so we are going to be done under budget and on time. We are today meeting or exceeding the sulfur targets that we established at our refineries to ensure that our on spec diesel can be delivered, and we are producing greater than 80% of our distillate stream as ultra-low sulfur diesel today, and also to date, we have converted over 70% of the 159 terminal tanks in our distribution system into ultra-low sulfur diesel.

Now turning to the Garyville major expansion project, Howard mentioned also the increase in the investment costs, and I want to review with you a couple of the major components of this project cost increase, which are mainly EPC contractor costs and construction management costs around the project, as well as some new optimization targets that we have within the plant.

We have decided to add six additional tanks into this project to allow for crude supply segregation and optionality of crudes that we can purchase around the world. We're also adding additional gasoline and diesel grade segregation tankage so that we have the optionality for water bomb barrels, Euro barrels, California, East Coast and Midwest fuels. We should be able to meet almost any spec in the world once we would complete this project.

We have also, as we first talked about this project last October, we have gone in through the front end engineering, and the completion of our feasibility engineering and increased some of the size of the units, the process units, namely the CCR platformer, the hydro cracker and the coker are all going to be increased in size to be able to process additional volumes to help balance the entire plant to where we have a full conversion facility when we complete.

In summary, while the project costs have increased, it's mainly due to this further optimization of the plant which is very typical as you go through the engineering phase, and we will complete the front end engineering and design in the fourth quarter of this year. And lastly, we have many project execution strategies in place in order to be able to handle the procurement and the long lead items for this very challenging project.

Now I'll turn it back over to Howard.

Thank you, Steve and Gary both for those updates.

Before moving to questions, I'd like to remind you to mark your calendars for our analyst days which we will hold on November 29th in New York and November 30th in London.

In the interest of fairness to all those wishing to ask a question, please limit yourself to one question and a related follow-up. You may then re-prompt if you have additional questions. Rebecca, with that, we will now open it up to questions.

[OPERATOR INSTRUCTIONS] Our first question comes from Robert Kessler with Simmons & Company.

Good afternoon, gentlemen.

I had a question, actually, on your Piceance Basin acquisition. In particular looking at your total expected recovery of 900 BCF and your well count of 700 which seemingly imply a fairly optimistic recovery per well.

It also looks as though you're expecting roughly 10 acres pacing which would also seem fairly dense. So I'm just wondering if you could characterize both of those the metrics relative to what you see elsewhere in the Piceance?

Robert, I'd be happy to. This is Steve Hinchman.

The development in the Piceance has been approved for up to 10-acre spacing, and the well performances in the area to date have basically showed no interference at 10-acre spacing. The recovery factor we're using on a gross per well per 10-acres is around 1.5 BCF.

As we look at the data, whether it's through the state records or the public information, the range on the 10-acre spacing is anywhere from 1.4 to 1.8 BCF per well. That's basically looking at over 250 wells really in the adjacent production to our acreage position.

So we feel pretty comfortable with our recovery in here. It fact, it might be a bit optimistic since we believe we can improve on some of the stimulation techniques in these completions.

Thank you, Steve.

Moving on next we'll here from Neil McMahon with Sanford Bernstein.

Hi.

Just again another question on the Piceance. Just comparing it, and I know it's difficult to follow deals that were done in the Piceance over the last year or so, it seems that the price paid was reasonably high indeed on the conference call from the acquired company or the acquired assets. It seemed like people were quite surprised at the price you paid.

I am just wondering what makes you feel that you can get more out of this than the previous operator and why you think you can accelerate the development faster than the previous operator? And I've got a follow-up as well.

Well, I think that we have some experience in Southwest Wyoming that I think's very relevant with the way we go about stimulating wells. We believe that we can enhance the value through improved stimulation techniques, and I think primarily just because of our capacity to fund the development that we can run at a harder pace than what the previous operator and accelerate the production.

Hey, Neil, this is Clarence.

Remember the other operator was largely using drilling funds to fund their program and were doing it at a much slower pace, so as Steve said, I think a big part of this is simply getting about the development, getting a higher level of rigs out there drilling and capturing the value.

Just as a follow-up, thanks for that. What gas prices or marginal costs were you assuming for the acquisition based on the acquisition price and over, obviously, a period of development which is going to last a number of years?

We use -- the price is really looking at $6 flat for Henry Hub.

Great. Thanks a lot.

Next we'll hear from Jennifer Rowland with JPMorgan.

Thanks.

A question on the downstream. I just wonder if you could comment on where you are as far as looking to potentially partner up with a Canadian oilsands producers and whether or not your desire to do that has changed at all?

Jenn, this is Clarence.

Our view is unchanged. We continue to see that there is great logic and a compelling business rational for an integrated solution from the wellhead all the way to the refinery around Canadian oilsands, but beyond that, you know, we would simply comment as we have before that we remain in discussion with Canadian producers around that kind of integrated transaction.

I think as we've said before, it is from a commercial standpoint and financial standpoint probably one of the more difficult kinds of transactions to put together, but our interest, our strategic view of the logic of that and the value of that to the Company remains unchanged and we continue to work that process.

Okay. Just a quick follow-up. When do you expect a final investment decision on Garyville expansion?

We will complete the FEED within the fourth quarter and present it to the board probably late fourth quarter.

Okay. Great. Thank you.

Moving on we'll hear from Mark Flannery with Credit Suisse.

I have another question on Garyville as well.

Gary, you mentioned that some of these units have been upsized. Can you give us an idea of how much they've been upsized or what impact that gives on either complexity or like product yields or something for the expansion?

Right. Mark, when we complete the FEED is when we will really be able to layout the, of course, what we expect to be the exact size of the units, but it mainly comes around the hydro cracker being increased about 10% from our base plan and the coking unit being increased about 10% from the base plan. And the other big unit is the platformer and that's about a 20 to 25% increase from the base plan.

All of those to be able to balance the type of crude that we already have in place and you look at the resid and the amount of conversion capacity we have in Garyville's plant today, and as we went in and started optimizing the new facility, it really was beneficial, more efficient and we could really leverage up the synergy within the two plants to be able to make those units, as I say, about 10 to 20% bigger.

So it'd be fair to say that you are interested in basically producing no resid at this new plan?

That would be the plan.

Thank you.

Next we'll hear from Steve Enger with Petrie Parkman.

Hi, guys. A couple of things.

One specific on production is all of the variability in your '06 full year production forecast at this point related essentially to Gulf of Mexico potential weather and then secondly, more broadly, a lot of your growth recently has been internationally. Now it looks like you're coming back and focusing more on the Bakken and Piceance. Does that signal kind of a change in your view of where the best opportunities are upstream?

To the first question, Steve, the production variance really from this point out in 2006 is really dominated by weather in the Gulf of Mexico. We do have a turnaround in our Brae B platform in the third quarter but predominantly it's weather in the Gulf of Mexico.

Steve, this is Dave Roberts and I'll comment on the second part of your question.

I think the opportunities that we're able to undertake in the United States sector are just an indication of our flexibility to pursue opportunities as they arise. We tend to align our business development activities with our core strengths, in this case some of strengths that Steve has already talked about.

I don't think that that limits us or indeed doesn't focus us purely on the domestic U.S. We'll continue to review activities and opportunities across our portfolio and globally.

Thanks.

From Bear Stearns we'll hear from Nikki Decker.

Good afternoon.

Gary, on your recent announcement on your intention to enter the ethanol business, maybe some color on the thought process there and where you are in the process towards construction of the first site?

Sure, Nikki.

Our strategy is that as we continue to grow the downstream business, our demand for ethanol is going to be about 850 million gallons per year going forward. When you look at some of the problems within the sector this spring, early summer, unless you had control of a gallon of ethanol, you possibly were going to leave nine gallons of gasoline in the tankage because you didn't have that gallon of ethanol to be able to blend to be able to meet some of the specs in certain markets.

As we go forward, we expect the total ethanol capacity to be about 6 to 6.5 billion gallons by the end of this year and it will continue to grow, but the biggest question is will it be in the right place, the right region of the country and have the capacity to either move by rail or by truck into the right markets. So being such a big supplier to the Midwest and the Southeast, we thought it was very prudent for us and strategic for us to have a certain amount of our required slate within our own production.

Is there any intention to manufacture E-85?

Well, today we have about a half dozen or so stations that can run E-85 through the station, and as we rebuild some of our Speedway stations and build some new units, we are considering at some of those units being able it put that additional tank in to be able to run E-85. Our long-term view of E-85 is that is not the answer to the supply concerns or the supply concerns of transportation fuels in the U.S.

So, yes, we can manufacture it, but it's just a blending operation. You just blend 85% ethanol with 15% gasoline in order to be able to do that, but the customer demand today is really negligible in any of our markets where we have E-85 offered today. So I would say definitely on the short-term we would have minimal investment in E-85 infrastructure.

Thank you. [OPERATOR INSTRUCTIONS]

From A.G. Edwards we'll hear from Ron Oster.

Good afternoon. Thank you.

Just a quick question on your second LNG train in Equatorial Guinea. I was just wondering if you can provide any update there in terms of any developments and if you could just go over some of the major obstacles that need to overcome to make that project move forward. And I had one follow-up question as well.

This is Dave Roberts.

I would just say that we're still engaged in pre-FEED activities and we're in active consultation with the government regarding the start of FEED, which we expect in the very near future. I don't think I would characterize anything at this time as a major obstacle to the project.

Okay. Great. Thank you.

And also on the international costs, they're a bit lower than we had expected, and I was just wondering -- I know you mentioned something about some changes in Ireland. I was just wondering if you could give us a run rate going forward and also if how much if any of that was related to the divestment of the Russian assets?

This is Steven Hinchman. As Howard had said, Russia has been eliminated from all of the numbers and previous comparisons so, and Russia has nothing to do with those numbers.

The costs going down from the first quarter to the second quarter really are primarily with fixed costs over a larger amount of volume with the additional overlifting that we have done, and we had provided guidance earlier around various cost components, fuel level controllable from 335 to 355, year-to-date we're running 329.

DD&A from 650 to 7 year-to-date, we're running around 665. And other costs we forecast 415 to about 450, and we're currently running around 450 today. So we're relatively on the high-end.

But that gives you some guidance internationally, and these costs exclude any foreign royalty and any FAS impairments but pretty much in line with the guidance that we had given earlier.

Great. Thank you.

Next we'll hear from Doug Leggate with Citigroup.

Thank you. Good afternoon, folks.

My question is on the expiration activity in the back half of this year, and I don't know if there is any opportunity to get some outlook for 2007. And specifically on Angola, what do you reckon now is a timeframe for likely sanctioning of at least one of those developments?

Yeah. Doug, this is Phil Behrman. Good afternoon. You have got several questions there.

Let me talk about the later half of 2006 first. I think as we mentioned in the earnings release we're drilling an appraisal well at the Stones discovery in the Gulf of Mexico. We have additional Gulf of Mexico well to be drilled in deepwater this year, and the remainder of our drilling will be with our three rigs that we have active in offshore Angola, two in Block 32 and one rig in Block 31 drilling continuously through the remainder of the year.

I think your second question was a forecast for 2007. It's a little early to provide a forecast for 2007. I think as Howard mentioned, we'll have an analyst meeting in November and probably give you very fulsome update of what we'll be planning not only in exploration but production as well as all of our business segments for 2007.

I think your last question was is the status of progressing towards the final investment decision and I think as we've told you before the furtherest progress is in Block 31 Northeast where we're moving forward on engineering on Block 31 Northeast. And the final investment decision should be in 2007 timeframe and so stay tuned. We'll give you that timing on that in the November meeting.

So it's unlikely I guess we will see any bookings in Angola this year. Is that fair?

No, we won't see any in bookings this year and we may not see any until sometime next year or thereafter.

Thanks very much.

Next from Lehman Brothers we'll hear from Paul Cheng.

Thank you. Hey, guys. I am wondering -- I think this is for Steve.

Steve, for the Piceance Basin can you give us what is the development cost and the yearly operating costs may look like?

The development cost is primarily tied up in the cost to drill and complete the wells, and we're estimating between 1.8 and $2 million to make location, drill and complete the wells. The unit operating cost, I guess, looking at the field controllable costs as well as shipping and handling out, we're probably looking at around $0.50 an MCF for that to maybe as high as $0.85.

So $0.50 to $0.85? And if I could just ask a somewhat unrelated question, this is for Gary.

Gary, some of your competitors that has been looking at expanding outside the U.S. in the refining side, I am wondering if you can talk about what is your inspiration here or that you don't believe that it is good for you guys.

Well, Paul, we booked a number of the opportunities in the international sector all the way from the Middle East, some of the European refiners and others, and so far we just have not found something that is, has been a strategic fit for us. And as outlined before with the Garyville expansion project, some, as Clarence mentioned, continuing to study some things on the Canadian side. We have plenty to say grace over here domestically.

But Gary, can you give us a -- when you look at internationally, what kind of criteria when you say strategically fit, what kind of aspect that you are looking for?

Well, as in any project, and where we believe we deliver the best value to our shareholders is where we can bring the entire package being our logistical strength, either being pipelines or terminals or some trading strength or an integrated value where the upstream will have oil that needs to be processed within a certain region, so we look at all those variables when we look at those projects, and as you know, we don't own any pipelines and terminals.

We are moving some barrels from Europe and other regions of the world into the East Coast and Gulf Coast of the U.S., but to this point in time, we just haven't found anything that brings all of those assets to fit into our long-term strategy.

Thank you.

And next from The Benchmark Company we'll hear from Mark Gilman.

Good afternoon. I've got a two part strategic downstream question if I could.

First with respect to Garyville, Gary, with the increase in costs my arithmetic, which is always subject to error, says that we're about 16,700 per daily on the upward revised costs and I'm wondering in light of that whether or not you might have considered an alternate host site since it would appear at that kind of cost number that there's really not much in the way of synergy with respect to the existing facility.

Well, Mark, first of all, your arithmetic appears to be pretty close. But we believe this project is the best project in the U.S. from an expansion standpoint and there is a tremendous amount of synergy with inside the battery limits and also outside the battery limits of that refinery via tankage, docks, pipelines, and we think it's a very strong project this far through the FEED And I must emphasize with the tremendous call on EPCs around the world, that we will not have our FEED finished until the fourth quarter of this year. But Mark, we still believe that it is the best project within the U.S. to be able to expand.

The second part of the strategic question regarding the study underway on the ethanol facilities, I'm wondering what you're assuming in terms of your feasibility analysis regarding the long-term sustainability of the existing tax credit as well as the price umbrella provided by the import tariff?

We believe that the tax subsidy that is in the marketplace today is going to be around for a long time, and we have stressed these projects with and without that tax subsidy to ensure that this project will float. Again, I want to emphasize that we are just, you know, this is the first project that we are considering, as our press release said, that we might consider a number of ethanol plants, we're walking into this, as I answered earlier, for our overall strategy of making sure we have some volume that we'll be able to blend and not leave any gasoline in inventory.

But the overall umbrella of a tariff on ethanol coming in, today there's some 7% or so of the Caribbean initiative is already coming in with no tax tariff on it, and the ethanol industry is competing very well against that. So to summarize, I don't believe the subsidy is going to go away, and I don't think the tariff is going to affect us that much going forward.

Thanks, Gary.

Yes.

Next we'll here from John Herrlin with Merrill Lynch.

Two quick ones.

With the tankage at Garyville, would you be able to handle the diluent turnaround for bitumen projects because some of the producers up in Canada have been talking about recycling the diluent. Would you be able to handle that?

John, that's a great question and that is not in our plan right now, it doesn't say it couldn't be. And that will all be predicated on what is the makeup of any bitumen that would have condensate, what the type of condensate is and how your downstream processing units are constructed to be able to handle that diluent or not handle that diluent.

Tankage, honestly, is very simple to build. If that were to be the case and you had a pipeline that could head back north into the Athabasca region, that would be simple to build the tankage. Today, this additional tankage is not being looked at for that purpose.

Great. Next one for me is on upstream.

On a cost incurred basis the last five years you've been spending about 20% on exploration. In the 90's your company was more in the 30% range. You've just bought some infill exploitation acreage between the Bakken and the Piceance.

How do you decide whether it's better for you to do infill exploitation or rank exploration? And with rank exploration are you more worried about project timing in terms of reaching fruition given the full engineering and construction yards?

John, this is Phil Behrman. Let me take a stab at answering your question.

It really is about portfolio and about how much risk spending that the Company wants to have. And it's about a diversification of that risk. We're very comfortable with a number of these low risk resource plays. Because of the skill base that Marathon has and the competencies that Marathon has, we feel we can exploit these very well and turn them into very profitable oil and gas developments.

In terms of the exploration opportunity, it's getting harder to compete around the world and so our challenge in the exploration phase is to make sure we prioritize and prioritize so that we don't bid away the value through either, in terms of the bidding process, the leasing process or through losing out in terms of the overall spending too much in terms of our cost structure.

So I guess I'd summarize by telling you I'm very comfortable that we're prioritizing well. We're continuing to see good low risk opportunities, and we continue to see high-risk opportunities.

Okay. Thanks.

For example, not only do our low risk opportunities and conduct those acquisitions in the Rockies, we just were high bidder in our block which is a higher risk frontier play in Indonesia, which is an example of that kind of diversification that Bob and I just mentioned previously. Our plans are to look at these on a one-on-one basis and prioritize them across the Company, not only in the upstream but look at all of our capital spend across upstream and downstream and make those investments.

Thank you.

Next from Deutsche Bank we'll hear from Paul Sankey.

As a follow-up to what you were just saying, the re-entry into Asia is some years after you actually exited Asia, why you aren't requiring higher potential returns there in order to make that move or could you in general talk more about your strategy of that re-entry? Thanks.

Paul, this is Phil Behrman again.

Our re-entry was predicated on several things. First of all, we saw a different opportunity set than when we exited Indonesia where we were looking at the shelf and some of the more mature areas of Indonesia. We see this as a higher risk but a very high reward opportunity.

Another thing has changed in Indonesia in particular are the terms. Previously a number of the terms were of the old 85/15 terms which diminished the overall profitability. What we see now are terms that are in the range of 60/40 or 65/35 terms, all of which allow us to explore profitably.

So we see this as a beachhead, a way to start in Indonesia where we see a lot of opportunity in a very complex geological area. So it's not just an opportunity for exploration. We'll use this beachhead to see what other business development opportunities and production opportunities might be out there in the future, too.

That sounds like it's specific to Indonesia as opposed to Asia.

I think we're going to look at this as a start for all of Southeast Asia, but we're focusing first on Indonesia.

Great. Thanks. And if I can ask a brief follow-up.

In Howard's comments he seemed to very specifically refer to the fact that sales of petroleum products were down as a result of higher prices. Could you just talk a little bit more about that? I thought it was a clear statement you were making.

And secondly about the dynamics of the diesel market, particularly regionally, in terms of what we're seeing as we head into the ultra-low sulfur diesel requirement. Thanks.

Sure. Paul, this is Gary.

Our best proxy to answer that question is Speedway same store gasoline volume, and then how we see the distillate volume going through our Pilot Travel Centers. But within Speedway for the quarter we were down about 1.9% on a same store, excuse me, 1.8% on a same store gasoline basis. And we're looking our numbers are for gasoline overall U.S. appears to be up about 0.6 of a percent. We believe the higher price is hitting -- as we really market in pad [two] as compared to the U.S. it is hitting the market a little greater than the entire U.S. average.

Excuse me, I should have said down 0.6% on gasoline.

You're talking to Q2 here, right, Gary?

I'm talking, that's year-to-date. I'm not talking 2Q, I'm talking year-to-date.

I'm sorry, Paul, the number I have here is -- I'm sorry, the total U.S. gasoline we're showing is up 0.6 of a percent. I did have it correct. It's up 0.6 of a percent and we're down 1.8.

The other thing is in a rising market where we are the leader in the marketplace, we have had to lead the price up much more than we have in prior months. And we're up against a very strong quarter last year that Speedway's numbers were up about 5% or so same period last year. So again, same store to same store we're down a little bit where we're comparing against a very strong second quarter last year.

On the distillate side, distillate -- overall freight traffic is down and secondly, the weight on the freight traffic is down which has led to lower demand on the overall diesel business. When you look at distillate year-to-date it appears to be up about 1 to 1.2% in that area. And our same store on distillate is continuing to perform pretty much on the market average that we've seen across the region.

And then ultra-low sulfur diesel is operating very, very well. We've not seen any problems so far. In fact, we believe all the big pipeline carriers and as I mentioned earlier, moving out of our refineries, we're being able to ship this material so far on spec and it gets to the terminals on spec.

Valero was just mentioning that they thought there was additional demand for ultra-low sulfur diesel where it wasn't available in certain markets. Do you have any thoughts on that?

We have, as I stated, about 80% of our refinery output is available in ultra-low sulfur diesel. There may be some specific region in the marketplace, we have not seen that so far in our markets that ultra-low sulfur is not available.

Okay. I'll leave it there. Thanks a lot, Gary.

Next from KeyBanc we'll hear from Jack Aydin.

Hi, guys. Two questions if I may.

On the Bakken well, the 300 barrels per day, is that an IP rate or how sustainable is it and what is the cost of that well and is it vertical or horizontal well?

Jack, that's an IP and no, they won't sustain at that. We expect that these wells will typically average around 300 barrels of oil equivalent per day. The well cost was around $4 million and these wells are drilled 10,000 foot vertically and 10,000 foot horizontally.

Thank you. The second question, I know you are in the Barnett Shale. [inaudible] I don't know, maybe I'm quoting something that I shouldn't maybe.

You have probably drilled about six to seven wells in Hamilton County and could you shed a little more color how well you're doing in those wells and what is your plan for the balance of the year in terms of drilling in the Barnett Shale wells?

We have drilled -- we've drilled five producers and one core test in Hamilton County. We're now waiting on a pipeline. We don't want to stimulate those wells without flowing them into a pipeline.

We anticipate that pipeline will be here in September. At that time we'll flow test those wells and then get more aggressive on our drilling program.

Any indication how many wells you might drill for the year, balance of the year?

We would run probably one rig this year and put two rigs out there next year.

Thank you.

Next from Petrie Parkman we'll hear from Steve Enger.

To clarify, make sure I'm clear on what you said earlier on exploration wells for the balance of this year, Stones plus one other in the deepwater Gulf of Mexico and could you share with us what that is and then are all the rest in Angola?

Yes. All the rest are in Angola and the other well will be in Green Canyon.

Any name or block?

It's called the Black Water well, and it's -- I might have this wrong, I believe it's Block 429. But I can't remember for sure the block number off the top of my head.

And then more broadly in exploration, do you feel like you need to develop an additional exploration core area like Angola, for example, it obviously has been working and likely will continue to, or are you for the size of Marathon and your aspirations, do you feel like you're okay going forward without adding a significant new exploratory core area?

I think, Steve, to answer your question that's why we accessed the opportunity in Indonesia. We're looking at that as the beginning of potential new exploration area, and our sense is that we want to add areas but we're going to be very selective in those areas that we do enter.

And how do you look at the Gulf of Mexico deepwater in that regard? Do you think that that's an area where you can have a few wells to drill or do you think with your acreage position that could really develop into something larger?

We continue at a slow pace simply because the well costs are very high, and again it's when we find hydrocarbons it's extremely profitable, but results haven't been as successful in the last couple years as they had been previously so we're going to go slow with very good opportunities and only good opportunities.

Great. Thanks.

Next we'll hear from Michael Young with Fidelity Investments.

Gentlemen, good afternoon and a question for Phil.

But if you could quantify what the expected tax impact is from the supplementary U.K. tax rate increase? And then more significantly, could you discuss the volume impact the improvement from the acceleration in the EGL and G train to the middle of next year?

I think on the U.K. supplemental tax we don't expect it to be material sitting here in the third quarter.

Do you want to define material, then?

I don't have a precise number for you at this point in time but it's not material.

Okay.

I'm trying to do the math in my head but I think about each month that we accelerate the start of the LNG that that represents probably around 4 to 5,000 barrels a day net annualized production.

Perfect. Thank you.

Next from A.G. Edwards we're hear from Ron Oster.

Gary, a quick question follow-up on the ethanol announcement. Our understanding is there's a bit of a limited number of construction slots as well as that the ideal locations for a 110-million gallon facility have kind of been picked over.

Could you kind of comment on that and with that in mind, just also comment on why you chose to go the grassroots route as opposed to possibly an acquisition?

Right, Ron, and we've looked at both, of course. An acquisition today is being priced very, very high in the market, and one of the real benefits of the grassroots that we're looking at here with our partner The Andersons is that they have a reservation slot to be able to get one built and get it built rapidly. So we're in the process right now of finalizing the site location along with the definitive agreements. And hopefully that will be concluded soon, and we'll be able to talk about the value of that reservation slot.

Okay. Can you disclose who that reservation slot is with?

No, I cannot.

And just one more.

You mentioned that you, going forward you plan on using about 850 million gallons of ethanol. Could you count on how much you're using presently?

Right around 550, maybe close to 600, but in that range.

Okay. Great. Thank you.

Rebecca, this is Howard. We probably have time for one more question and a follow-up.

We'll take our last question from Mark Gilman with The Benchmark Company.

Guys, just so we can get a better handle around these international cost issues, can you give us an idea what the D&A operating cost and other costs, Howard, were for KMOC prior to eliminating it from the figures?

I don't have those at my fingertips. Steve? Do you? If not, we can get back to you on that, Mark.

The operating costs for KMOC in general was around $2 a barrel. DD&A was around I think $6 a barrel and going off the top of my head, Mark. But more specific than that, I don't know. I'd have to get back to you.

Okay. Thanks very much.

Okay, Rebecca, with that we will wrap it up. We appreciate everyone's interest and continued support of Marathon. Have a good day.

That does conclude today's presentation. We do thank everyone for their participation. Have a wonderful day.