8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): October 27, 2005

MARATHON OIL CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	1-5153	25-0996816
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

5555 San Felipe Road, Houston, Texas	77056-2723
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 629-6600

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02	Results of Operations and Financial Condition.
	On October 27, 2005, Marathon Oil Corporation (Marathon) held a dial-in conference call and webcast discussing third quarter 2005 earnings. The presentation is being furnished as an exhibit to this report and is incorporated herein by reference.
Item 9.01	Financial Statements and Exhibits.
	(c)	Exhibits.
	99.1	Presentation dated October 27, 2005, by Marathon Oil Corporation.

2

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	MARATHON OIL CORPORATION
Date: November 1, 2005		By:	/s/ A.G. Adkins
			A.G. Adkins
			Vice President-Accounting

3

EXHIBIT INDEX

Number	Exhibit
99.1	Presentation dated October 27, 2005, discussing Marathon’s financial results for the third quarter 2005.

4

EX-99.1

Exhibit 99.1

Searchable text section of graphics shown above

Third Quarter 2005
Earnings Conference Call and
Web Cast

October 27, 2005

[LOGO]

Forward Looking Statement

Except for historical information, this presentation contains forward-looking information with respect to the timing and levels of the company’s worldwide liquid hydrocarbon and natural gas and condensate production, integrated gas segment earnings, net interest, administrative and exploration expenses, the Alvheim/Vilje development projects and possible Hamsun development, exploration and drilling plans, the re-entry into Libya, the LNG project along with possible expansions and refinery expansions at the Detroit and Garyville facilities. These statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied from such information. The projected earnings and expense items are preliminary estimates and are subject to change. In accordance with the “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, 2004, and in subsequent Forms 10-Q and 8-K, cautionary language identifying important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Other Information

In addition to net income determined in accordance with generally accepted accounting principles (GAAP), Marathon has provided supplementally “net income adjusted for special items,” a non-GAAP financial measure which facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties. Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to Marathon's ongoing operations. A reconciliation between GAAP net income and “net income adjusted for special items” is provided in a table on slide 3. “Net income adjusted for special items” should not be considered a substitute for net income as reported in accordance with GAAP.

Management, as well as certain investors, uses “net income adjusted for special items” to evaluate Marathon's financial performance between periods. Management also uses “net income adjusted for special items” to compare Marathon's performance to certain competitors.

[LOGO]

2

Adjusted Net Income

[BAR GRAPH]

	1Q 2004	2Q 2004	3Q 2004	4Q 2004	1Q 2005	2Q 2005	3Q 2005
Net Income	258	352	222	429	324	673	770
UK Gas Cont.	-8	55	75	-65	33	97	48
Ins Adj				17
Impairment				34
Def Tax Adj						-15
Gain On Sale							-21
Adj Net Income*	250	407	297	415	357	755	797

* See slide two of this presentation for a discussion of the use of the non-GAAP measure adjusted net income (net income adjusted for special items).

[LOGO]

3

Adjusted Net Income Per Share

[BAR GRAPH]

* See slide three of this presentation for a reconciliation of Adjusted NI to Net Income. See slide two of this presentation for a discussion of the use of the non-GAAP measure adjusted net income (net income adjusted for special items).

[LOGO]

4

Total Segment Income

[BAR GRAPH]

[LOGO]

5

Upstream Segment

Income and Worldwide Sales Volumes

[BAR GRAPH]

Avg Realized Price ($/BOE)	27.16	28.89	30.56	32.18	33.08	38.16	42.26
Sales Volumes:
Liquids (MBD)	184	178	157	162	163	219	157
Gas (MMCFD)	1136	965	901	996	1025	893	807
Total (MBOED)	373	339	307	328	334	368	292

[LOGO]

6

Domestic Upstream

Income and Sales Volumes

[BAR GRAPH]

NYMEX prompt WTI ($/Bbl)	35.25	38.28	43.89	48.27	50.03	53.22	63.31
Bid Week Nat Gas ($/MCF)	5.69	5.98	5.77	7.07	6.27	6.74	8.53
Avg Realized Prices:
Liquids ($/Bbl)	29.74	31.74	35.56	34.84	38.47	42.22	52.38
Natural Gas ($/MCF)	4.71	5.02	4.76	5.09	4.95	5.76	6.56
Lower 48 Gas ($/MCF)	5.51	5.78	5.65	6.35	5.81	6.50	7.88

[LOGO]

7

Domestic Income

[BAR GRAPH]

[LOGO]

8

Domestic Income

Sales Volumes and Expenses

[BAR GRAPH]

Total Exp. ($/BOE)	12.55	14.25	14.34	17.62	17.54	16.12	18.15
Sales Volumes:
Liquids (MBD)	92	87	81	65	72	86	71
Nat Gas (MMCFD)	701	641	598	585	570	579	562
Total (MBOED)	209	194	180	163	167	182	165

[LOGO]

9

Domestic Upstream

Expenses and Profitability

[LINE GRAPH]

($/BOE)
Avg. Realized Price	28.92	30.86	31.70	32.25	33.45	38.15	44.96
Expenses	12.55	14.25	14.34	17.62	17.54	16.12	18.15
Income per BOE	16.14	16.09	14.73	15.84	20.32	23.79	26.26

[LOGO]

10

International Upstream

Income and Sales Volumes

[BAR GRAPH]

Dated Brent ($/Bbl)	32.03	35.32	41.54	43.85	47.62	51.63	61.63
Avg Realized prices:
Liquids ($/Bbl)	28.22	30.91	37.07	38.72	39.10	45.53	48.24
Natural Gas ($/MMCF)	3.46	3.07	2.79	3.79	4.17	3.22	3.12

[LOGO]

11

International Income

[BAR GRAPH]

[LOGO]

12

International Upstream

Sales Volumes and Expenses

[BAR GRAPH]

Total Exp. ($/BOE)	15.40	15.54	19.44	17.95	17.03	18.26	23.29
Sales Volumes:
Liquids (MBD)	92	91	76	97	91	134	86
Nat Gas (MMCFD)	435	324	303	411	455	313	245
Total (MBOED)	165	145	127	165	167	186	127

[LOGO]

13

International Upstream

Expenses and Profitability

[BAR GRAPH]

($/BOE)
Avg. Realized Prices	24.92	26.24	28.94	32.10	32.71	38.16	38.76
Expenses	15.40	15.54	19.44	17.95	17.03	18.26	23.29
Income per BOE	10.55	11.67	9.13	13.50	16.61	22.57	19.72

[LOGO]

14

Downstream Segment

Income and Refinery Throughputs

[BAR GRAPH]

Ref/Wholesale margin ($/gal)	.0344	.1255	.0900	.0959	.0685	.1592	.1774
Total Throughputs (MBD)	985	1,155	1,123	1,175	1,094	1,186	1,195
Market Prices:
Chicago 6-3-2-1 ($/Bbl)	3.99	6.65	3.30	0.93	2.59	6.46	10.52
USGC 6-3-2-1 ($/Bbl)	3.72	5.06	2.47	0.14	2.12	5.79	11.06
Sweet/Sour Differential * ($/Bbl)	5.87	7.09	7.77	11.15	12.09	10.72	9.52

* Sour = 15% Bow River, 15% Maya, 35% Kuwait, 35% Arab Medium

15

SSA

Gasoline/Distillate Sales and Gross Margins

[BAR GRAPH]

SSA Retail Units	1,773	1,746	1,685	1,669	1,659	1,647	1,638
Light products margin (Cents/Gal)	11.45	11.92	11.85	12.19	10.58	12.11	12.32
Merch. Sales ($MM)	521	600	632	581	560	645	689
Merch. Margin ($MM)	132	140	154	145	143	163	162
% Margin	25.3	23.3	24.4	25.0	25.5	25.3	23.5

[LOGO]

16

Integrated Gas and Corporate

	2Q A	3Q A
Integrated Gas Segment Earnings ($ millions)	11	(6	)
Unallocated Administrative Expense ($ millions)	85	108
Net Interest Expense ($ millions)	35	32
Effective Tax Rate (Percent)	33.3	37.9
Cash Adjusted Debt ($ millions)	3,104	3,286

[LOGO]

17

3Q 2005 Estimates and Prior Actuals

	2004 Actuals					2005
	1Q	2Q		3Q	4Q	1Q A	2Q A	3Q A		4Q E
Domestic Production and Sales:
Liquids (MBD)	92	87		81	65	72	86	71		70-75
Nat Gas (MMCFD)	701	641		598	585	570	579	562		605-625
Domestic Total (MBOED)	209	194		180	163	167	182	165		171-179
International Sales Volumes*:
Liquids (MBD) *	92	91		76	97	91	134	86		116-124
Nat Gas (MMCFD)	435	324		303	411	455	313	245		375-400
Int’l Total (MBOED)	165	145		127	165	167	186	127		179-191
Total WW Production (MBOED)	373	339		307	328	334	368	292		350-370
Integrated Gas Segment Earnings ($ millions)	15	(8	)	18	23	7	11	(6	)	10
Net Interest Expense ($ millions)	38	51		40	32	32	35	32		21
Unallocated Administrative Expense ($ millions)	64	84		90	69	91	85	108		60-70
Exploration Expense:
Domestic ($ millions)	11	21		15	31	17	25	18		30-50
International ($ millions)	17	13		31	31	17	12	46		20-40
Effective Tax Rate (Percent)	39.0	38.1		36.5	33.4	38.0	33.3	37.9		36-37

* The estimated sales volumes shown for 4Q 2005 are based upon production available for sale. Production available for sale may vary materially from production sold in any given period based on the timing of liquid hydrocarbon liftings, primarily in international operations.

[LOGO]

18

Third Quarter 2005

Earnings Conference Call and

Web Cast

October 27, 2005

[LOGO]

19

Garyville Expansion

Leveraging a World Class Asset

•Total costs ~ $2.2 billion

•Estimated project completion late 2009

•180,000 b/d crude throughput

–Crude unit

–Coker

–Hydrotreating

–Reformer

–Sulfur plants

–Additional heavy crude

[LOGO]

20

Operator

Good day, everyone, and welcome to this Marathon Oil Corporation third quarter 2005 earnings conference call. Today’s call is being recorded. For opening remarks and introductions, I would like to turn the call over to Mr. Ken Matheny, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Ken Matheny — Marathon Oil Corporation - VP of IR and Public Affairs

Thank you very much, Patty, and I too would like to welcome everyone to the third quarter 2005 earnings webcast and teleconference for Marathon Oil Corporation. Let me begin by reminding you that if you are listening via telephone, you can find the synchronized slides that accompany this call on our website at www.Marathon.com.

With me on the call today are Clarence Cazalot, President and CEO; Janet Clark, Senior Vice President and Chief Financial Officer; Phil Behrman, Senior Vice President of Worldwide Exploration; Steve Hinchman, Senior Vice President of Worldwide Production; and Gary Heminger, Executive Vice President and President of our Refining, Marketing and Transportation Organization; and Garry Peiffer, Senior Vice President of Finance and Commercial Services for our downstream organization. Approximately two hours after this call ends, these remarks and the slides will be placed on the Investor Relations portion of our website. It will remain on the site for one year.

Slide No. 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 31st, 2004, and in subsequent Form 10-K and 8-K filings 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 shown on Slide No. 3, net income for the third quarter was $770 million, and included two special items totaling a negative $27 million after tax, resulting in net income adjusted for special items of $797 million. The two after-tax special items were a negative $48 million mark-to-market loss on our two long-term UK gas contracts, and a $21 million gain on the sale of a 15% interest in Equatorial Guinea LNG Holdings Limited.

Net income adjusted for special items of $797 million was $42 million more than the second quarter of this year, and 168% greater than the third quarter of last year. The sequential improvement as well as the improvement year-over-year was largely a result of the elimination of the minority interest in our downstream business, strong refining and marketing margins, along with record refinery throughput, and increased liquids and natural gas prices somewhat offset by lower upstream production sales. A reconciliation of net income adjusted for special items to net income is included on Slide 3. You can refer to Slide 2 for a discussion of the use of this non-GAAP measure.

Moving to Slide No. 4, net income adjusted for special items on a per share basis, equaled that of the second quarter at $2.16 per diluted share, but I will note that approximately 19 million more shares were outstanding this quarter. The additional shares outstanding were largely a result of the downstream minority interest acquisition we closed on June 30th.

As shown on Slide No. 5, third quarter segment income was $1.435 billion, $175 million less than the second quarter, but almost double that of the same quarter last year. A major factor in the decrease from the second quarter was lower upstream sales volumes, partially offset by higher liquid and natural gas prices in the upstream segment. Worldwide upstream sales volumes were down, largely as a result of liquid hydrocarbon underliftings in the United Kingdom, Equatorial Guinea and Gabon, and the four storms, two of which were major hurricanes that hit the Gulf of Mexico during the third quarter.

Upstream segment income of $627 million is shown on Slide No. 6. It was down $149 million quarter-over-quarter. Domestic upstream segment income of $397 million as shown on Slide No. 7, was relatively flat for the second quarter. Domestic liquid realizations were up over $10 while natural gas was up a less robust $0.80. Again, production sold was adversely affected by the significant storm activity during the quarter in the Gulf of Mexico.

Slide No. 8 demonstrates how domestic upstream income benefited over $100 million from higher prices, while lower volumes reduced operating income in the segment — operating income in the segment by approximately $60 million compared to the second

quarter. Other revenues were $27 million lower during the quarter, primarily as a result of the gain on the sale of East Cameroon block 321 that occurred in the second quarter. Other fluctuations, mainly increased production taxes in the current quarter and second quarter insurance related to Petronius amounted to a negative $17 million.

Total expenses in the domestic upstream segment, as shown on Slide 9, were up $2 per barrel of oil equivalent compared to the second quarter. Excluding exploration expense, which can vary based on the timing of dry holes, expenses were up $2.32 per barrel of oil equivalent from $14.64 to $16.96 per boe. This increase is largely a result of the higher production taxes related to higher commodity prices, increased per barrel operating cost due to reduced volumes, higher G&A allocations, and lower insurance recoveries related to Petronius. For the year, we’d expect on a barrel of oil equivalent basis domestic field level expenses to be $3.35 to $3.40, DD&A of around $6.70, and all other costs, excluding production taxes, to be about $4. At current prices, domestic production taxes are approximately $2.10 per barrel of oil equivalent.

Moving to Slide 10, domestic upstream income per barrel of oil equivalent increased 10% over the second quarter, reflecting the 18% increase in the average liquids and natural gas realizations, partially offset by the previously discussed increase in the average cost per barrel equivalent.

Moving to international upstream, as shown on Slide No. 11, international income of $230 million was sharply lower than the second quarter, mainly as a result of the timing of international liquids in the United Kingdom, Equatorial Guinea, and Gabon. Slide 12 shows that the underlift in international hydrocarbon sales reduced international upstream income by over $200 million, but this was somewhat offset by lower DD&A of $42 million, again related to those liftings. Higher price realizations increased segment income $20 million, while exploration expense was $34 million higher in the second quarter, primarily a result of writing off the Annapolis well offshore Nova Scotia. All other changes amounted to a positive $31 million for the quarter, mainly a result of lower controllable costs, due to the timing of liftings.

Moving to Slide No. 13, total international upstream sales volumes decreased 32% compared to the second quarter, while liquid hydrocarbon sales volumes decreased 36%, again, primarily a result of our underlift positions. Lower natural gas sales volumes were the result of lower spot gas sales in the United Kingdom and higher injections to storage in Ireland. International upstream expenses excluding — excluding exploration expense increased approximately 10% on a barrel of oil equivalent basis compared to the second quarter, primarily the result of higher Russian production taxes, and increased expenses associated with a start-up of our Equatorial Guinea LPG plant and lower volumes and a change in production mix due to our underlift position.

For the year we’d expect on a barrel of oil equivalent basis international field level expenses to be approximately $3.45 per boe, DD&A of around $7, and all other excluding production taxes to be about $4.25. At current prices, international production taxes are approximately $2 per barrel of oil equivalent.

Slide 14 shows that international upstream income per boe fell 13% compared to the second quarter, largely the result of the higher exploration expenses and previously discussed higher production taxes and our change in mix quarter over quarter. Concluding the upstream segment discussion, despite losing approximately 20,000 barrels of oil equivalent per day as a result of the storm activity in the Gulf of Mexico, production available for sale was within 1,000 barrels a day of the estimated production range for the quarter, as a result of strong performance from other regions, primarily in Russia, and Equatorial Guinea.

Moving to our downstream business in Slide 15, third quarter segment income of $814 million was more than double the $391 million third quarter 2004 segment income. And because of the seasonality in the downstream business, I will compare the third quarter 2005 results against the same quarter in 2004. The single largest factor contributing to the downstream improvement was a significant improvement in crack spreads. On a two-thirds Chicago and one-third U.S. Gulf Coast basis, the WTI 3-2-1 average for the third quarter was $17.53 per barrel, compared to $7.37 per barrel in the same quarter last year. The WTI 6-3-2-1 crack spread, which better approximates Marathon’s total production rate, also improved substantially, increasing from about $3.02 per barrel in the the third quarter of 2004, on a two-thirds Chicago and one-third U.S. Gulf Coast basis, to $10.70 per barrel in the third quarter.

Just the improvement in the WTI 6-3-2-1 crack spread would have added about $800 million to downstream earnings compared to the third quarter of 2004. However, the rapid increase in spot market prices used in these indicator crack spreads, particularly in September, was only partially passed along to our wholesale and branded customers. In addition, the price of our non-gasoline and non-distillate products traditionally lags light product spot market price changes. These two factors had a negative effect of approximately $500 million when compared to the indicated WTI 6-3-2-1 crack spread increases.

The crude oil in transit effect was a negative $37 million in the current quarter, versus a negative $70 million in the third quarter of last year, a $33 million positive impact. All the other variances last quarter resulting from the record total refinery throughputs we

achieved at our refineries last quarter, wider sweet/sour differentials, which were partially offset by higher expenses and other costs, accounted for the remainder of the quarter-to-quarter variance.

As shown on Slide 16, Speedway SuperAmerica’s gasoline and distillate sales were up about 31 million gallons quarter-over-quarter or about 4%. Same-store gasoline sales were up about 5%, even though Speedway SuperAmerica’s retail gasoline prices averaged $2.45 per gallon in the quarter just completed, compared to $1.81 per gallon in the same quarter last year. Speedway SuperAmerica’s merchandise sales on a same-store basis increased almost 11% last quarter from the same quarter last year, and this marked the 11th consecutive quarter that Speedway SuperAmerica’s merchandise sales have increased over 9% on a same-store basis.

Turning to slide 17, the integrated gas segment incurred a $6 million loss during the the third quarter of 2005, compared to income of $11 million in the second quarter 2005. The decrease was primarily the result of mark-to-market changes in the fair value of derivatives used to support gas marketing activities. In the unallocated category, administrative expenses were $108 million in the third quarter. The increase from the second quarter total of $85 million was due primarily to an increase in the non-cash charge related to equity-based compensation, as our share price increased by more than $15 during the quarter.

Net interest and other financing costs were $32 million in the third quarter, $3 million lower than the second quarter, largely a result of higher capitalized interest, partially offset by reduced interest income in the current quarter. Pretax income for the the third quarter was $1.2 billion, and the tax provision was $469 million for a 37.9% effective tax rate. This was higher than our guidance, due to adjustments to income tax accruals and the tax treatment of certain derivative instruments, and we now expect our tax rate to be in the 36 to 37% range for the year.

Cash adjusted debt went up by $182 million during the the third quarter to $3.286 billion. Cash adjusted debt-to-capital  at September 30th, 2005 is approximately 24%, and I’ll note that that cash adjusted debt balance continues to include approximately $587 million of debt that’s serviced by United States steel. I will remind you, these are preliminary numbers. Third quarter preliminary cash flow from operations was approximately $449 million. Preliminary cash flow from operations before working capital changes was approximately $1.05 billion. And for the first nine months, preliminary cash flow from operations was approximately $1.963 billion and approximately $3.27 billion before working capital changes.

Finally, Slide 18 provides information from prior quarters, as well as estimates for the fourth quarter. Total liquids production available for sale in the fourth quarter is expected to be approximately 186,000 to 199,000 barrels per day. The increase over the third quarter is expected as a result of lower hurricane down time. Worldwide gas production is estimated at 980 million to 1 billion 25 million cubic feet per day, higher than the third quarter because of seasonal gas sales in Europe and Alaska, and, again, lower hurricane downtime in the Gulf of Mexico.

Total production available for sale for the fourth quarter therefore, is estimated at 350,000 to 370,000 barrels of oil equivalent per day. While we cannot predict the exact timing of liftings, given our significant underlift position of approximately 2.5 million barrels at the end of the third quarter, production sales for the fourth quarter are likely to fall between the production available for sale just provided and 380,000-barrels of oil equivalent per day. Finally, we now estimate 2005 production available for sale to be between 340,000 and 350,000 barrels of oil equivalent per day, excluding the impact of any acquisitions, dispositions, or of our potential re-entry into Libya.

Now I’d like to turn the call over to Clarence Cazalot who will provide comments about our results and forward plans.

Clarence Cazalot — Marathon Oil Corporation - President, CEO

Good afternoon, everyone. Marathon had another very strong operational and financial quarter despite the storm disruptions. And thankfully our employees and their families didn’t sustain any significant injuries during the evacuations or during the storms. And I’m really very proud of the way our employees have responded in an extraordinary manner, restoring operations both upstream and downstream shortly after the storms. But their response did not stop there, as the Company and our employees along with our dealers, jobbers and wholesale customers have now contributed over $8.5 million to the relief effort.

I think as I spoke to you at the last teleconference, we continue to focus on safety and environmental stewardship. Through September, we continue to have lower rates, both in safety and environmental incidents, almost across the board in our operations. As compared to both 2004 and compared to our goals for 2005. It’s an area in which we will continue to remain focused and vigilant.

Because of the hurricanes during the quarter, our entire Gulf of Mexico production was down for what amounted to more than one full month. While this reduced production and sales about 20,000 boe per day, as Ken already said, we were fortunate in that we didn’t sustain any major damage and have been able to bring back our production on stream to over 90% from the Gulf in a very timely

manner. During this period, we had very strong production results from Equatorial Guinea and Russia that helped to offset some of that reduced Gulf of Mexico output. EG Phase II, which is the liquid expansion, both condensate and LGP continues to exceed our expectations. And in Russia, our East Kamennoye Vickulov development continues to perform well, with total Russian production now in the 30,000 barrel per day range and I would remind you that at the time we made the acquisition, in mid-2003, production from that asset was 15,000 barrels per day.

Our development projects are progressing as planned. The Alvheim Vilje project in Norway is 29% complete and progressing on schedule, and we continue to look at options to tie back the 2004 Hamsun discovery to this development. And as Ken mentioned, we continue to have exploration success, with our two Angola discoveries in this quarter, bringing the total discoveries in blocks 31 and 32 now to 12.

The Equatorial Guinea LNG Train 1 project is now 58% complete and ahead of schedule. With about $1 billion expended to date, it is also on budget, with first LNG deliveries expected in 2007. And we continue to move forward with our studies and our work towards justifying a second train there on Bioko Island.

Let me turn to the downstream. In the first quarter which we now had 100% ownership of the downstream operations, we set a new record for total throughputs at almost 1.2 million barrels per day, and this was done in spite of its disruptions from the two major hurricanes that reduced our total throughputs by about 40,000 barrels per day for the quarter. Again, I think another testament to the dedication and the hard work of our employees and really the value of this business.

We also took the Detroit refinery down September 29th, to tie in the expansion and the low sulfur facilities and the refinery is now expected to be back in operation by mid-November, taking this refinery from 74,000 to 100,000 barrels of crude throughput per day. And finally, moving to Slide 20, we announced this morning that we are entering the front-end engineering design or the FEED phase for an expansion project at our Garyville refinery in Louisiana. We have completed our feasibility phase of that project, and expect the FEED to take up to a year, which will likely place our final investment decision in the fourth quarter of next year.

With an estimated cost, preliminary estimated cost of $2.2 billion, this major expansion would add 180,000 barrels of crude throughput to this already large 245,000 barrel per day world-class refinery. With major new components, including a crude unit, coker, reformer and hydrocracker, this will be a major undertaking. Importantly, it will also allow us to better balance volumes through the existing facilities at Garyville, expand our use of heavy high sulfur crude and utilize existing pipelines and storage facilities. Once completed, this expansion will enable Marathon to supply the nation with nearly 6 million additional gallons per day of ultra clean fuels, including gasoline and distillates. This project provides an outstanding strategic fit to our existing refining network, including accessibility to numerous product transportation systems that serve key markets throughout the U.S.

In addition to completing a successful FEED, we will need the necessary permits and a continued favorable investment climate to move forward with this project, but we believe the expansion of our Garyville refinery demonstrates the kinds of substantial capital investments we are making in both our upstream and downstream operations to help us meet the growing energy needs of consumers while providing what we believe to be superior value growth for our shareholders.