(In millions) | | E&P | | RM&T | | IG | | Total | |
Six Months Ended June 30, 2006 | | | | | | | | | |
Revenues: | | | | | | | | | |
Customer | | $ | 4,433 | | $ | 29,280 | | $ | 100 | | $ | 33,813 | |
Intersegment (a) | | 377 | | 15 | | — | | 392 | |
Related parties | | 6 | | 717 | | — | | 723 | |
| | | | | | | | | |
Segment revenues | | 4,816 | | 30,012 | | 100 | | 34,928 | |
Elimination of intersegment revenues | | (377 | ) | (15 | ) | — | | (392 | ) |
Gain on long-term U.K. natural gas contracts | | 61 | | — | | — | | 61 | |
| | | | | | | | | |
Total revenues | | $ | 4,500 | | $ | 29,997 | | $ | 100 | | $ | 34,597 | |
| | | | | | | | | |
Segment income | | $ | 1,124 | | $ | 1,236 | | $ | 25 | | $ | 2,385 | |
| | | | | | | | | |
Income from equity method investments | | 106 | | 58 | | 25 | | 189 | |
| | | | | | | | | |
Depreciation, depletion and amortization (b) | | 477 | | 270 | | 4 | | 751 | |
Minority interests in loss of subsidiary | | — | | — | | (5 | ) | (5 | ) |
| | | | | | | | | |
Income tax provision (b) | | 1,196 | | 768 | | 4 | | 1,968 | |
| | | | | | | | | |
Capital expenditures (c) | | 821 | | 304 | | 164 | | 1,289 | |
(a) Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
(b) Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities and other unallocated items and are included in “Items not allocated to segments, net of income taxes” in the reconciliation below.
(c) Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities.
The following reconciles segment income to net income as reported in the consolidated statements of income:
| | Second Quarter Ended | | Six Months Ended | |
| | June 30, | | June 30, | |
(In millions) | | 2007 | | 2006 | | 2007 | | 2006 | |
Segment income | | $ | 1,658 | | $ | 1,593 | | $ | 2,407 | | $ | 2,385 | |
Items not allocated to segments, net of income taxes: | | | | | | | | | |
Corporate and other unallocated items | | (111 | ) | (99 | ) | (154 | ) | (165 | ) |
Gain (loss) on long-term U.K. natural gas contracts | | (5 | ) | (10 | ) | 6 | | 35 | |
Discontinued operations | | 8 | | 264 | | 8 | | 277 | |
Net income | | $ | 1,550 | | $ | 1,748 | | $ | 2,267 | | $ | 2,532 | |
8. Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
| | Second Quarter Ended June 30, | |
| | Pension Benefits | | Other Benefits | |
(In millions) | | 2007 | | 2006 | | 2007 | | 2006 | |
Service cost | | $ | 37 | | $ | 32 | | $ | 6 | | $ | 6 | |
Interest cost | | 37 | | 31 | | 11 | | 11 | |
Expected return on plan assets | | (39 | ) | (29 | ) | — | | — | |
Amortization: | | | | | | | | | |
– prior service cost (credit) | | 4 | | 1 | | (3 | ) | (3 | ) |
– actuarial loss | | 13 | | 11 | | 2 | | 2 | |
Multi-employer and other plans | | 1 | | 1 | | 1 | | 2 | |
| | | | | | | | | |
Net periodic benefit cost | | $ | 53 | | $ | 47 | | $ | 17 | | $ | 18 | |
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| | Six Months Ended June 30, | |
| | Pension Benefits | | Other Benefits | |
(In millions) | | 2007 | | 2006 | | 2007 | | 2006 | |
Service cost | | $ | 70 | | $ | 66 | | $ | 11 | | $ | 12 | |
Interest cost | | 71 | | 63 | | 22 | | 21 | |
Expected return on plan assets | | (77 | ) | (55 | ) | — | | — | |
Amortization: | | | | | | | | | |
– prior service cost (credit) | | 7 | | 2 | | (5 | ) | (6 | ) |
– actuarial loss | | 18 | | 24 | | 4 | | 4 | |
Multi-employer and other plans | | 1 | | 1 | | 1 | | 2 | |
| | | | | | | | | |
Net periodic benefit cost | | $ | 90 | | $ | 101 | | $ | 33 | | $ | 33 | |
During the first six months of 2007, Marathon made contributions of $73 million to its funded pension plans, including $43 million related to international plans. Marathon expects to make additional contributions of approximately $8 million to its funded pension plans over the remainder of 2007. Contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $8 million and $16 million during the first six months of 2007.
9. Income Taxes
The provision for income taxes for interim periods is based on management’s best estimate of the effective income tax rate expected to be applicable for the current year plus any adjustments arising from a change in the estimated amount of taxes related to prior periods. The following is an analysis of the effective income tax rates for continuing operations for the periods presented:
| | Second Quarter Ended
June 30, | | Six Months Ended
June 30, | |
| | 2007 | | 2006 | | 2007 | | 2006 | |
Statutory U.S. income tax rate | | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % |
Effects of foreign operations, including foreign tax credits | | 8.4 | | 9.9 | | 9.2 | | 10.4 | |
State and local income taxes, net of federal income tax effects | | 2.2 | | 2.0 | | 2.1 | | 2.0 | |
Other tax effects | | (1.1 | ) | (0.6 | ) | (1.3 | ) | (0.8 | ) |
Effective income tax rate for continuing operations | | 44.5 | % | 46.3 | % | 45.0 | % | 46.6 | % |
As of January 1, 2007, total unrecognized tax benefits were $48 million. If these amounts were recognized, $30 million would affect Marathon’s effective income tax rate. There are no uncertain income tax positions as of January 1, 2007 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during 2007.
Marathon is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue Service. The audit of the 2004 and 2005 U.S. federal income tax returns commenced in May 2006 and is ongoing. Marathon believes it has made adequate provision for federal income taxes and interest which may become payable for years not yet settled. Further, Marathon is routinely involved in U.S. state and local income tax audits and foreign jurisdiction tax audits. Marathon’s income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:
United States (a) | | 1999 – 2006 | |
Equatorial Guinea | | 2004 – 2006 | |
Libya | | 2006 | |
United Kingdom | | 2005 – 2006 | |
(a) Includes federal, state and local jurisdictions.
In connection with the adoption of FIN No. 48, Marathon changed the presentation of interest and penalties related to income taxes in the consolidated statement of income. Effective January 1, 2007, such interest and penalties are prospectively recorded as part of the provision for income taxes. Prior to January 1, 2007, Marathon recorded such interest as part of net interest and other financing costs and such penalties as selling, general and administrative expenses. As of January 1, 2007, $17 million of interest and penalties was accrued related to income taxes.
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10. Comprehensive Income
The following sets forth Marathon’s comprehensive income for the periods indicated:
| | Second Quarter Ended | | Six Months Ended | |
| | June 30, | | June 30, | |
(In millions) | | 2007 | | 2006 | | 2007 | | 2006 | |
Net income | | $ | 1,550 | | $ | 1,748 | | $ | 2,267 | | $ | 2,532 | |
Other comprehensive income, net of taxes: | | | | | | | | | |
Minimum pension liability adjustments | | — | | 5 | | — | | 15 | |
Defined benefit postretirement plans (a) | | (89 | ) | — | | (53 | ) | — | |
Other | | (3 | ) | 4 | | (1 | ) | 4 | |
Comprehensive income | | $ | 1,458 | | $ | 1,757 | | $ | 2,213 | | $ | 2,551 | |
(a) During the first six months of 2007, changes were made to the estimates used to measure certain assumptions necessary in determining the funded status of Marathon's postretirement benefit plans as of December 31, 2006.
11. Inventories
Inventories are carried at the lower of cost or market value. The cost of inventories of crude oil, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method.
(In millions) | | June 30,
2007 | | December 31,
2006 | |
Liquid hydrocarbons and natural gas | | $ | 2,087 | | $ | 1,136 | |
Refined products and merchandise | | 1,990 | | 1,812 | |
Supplies and sundry items | | 233 | | 225 | |
| | | | | |
Total, at cost | | $ | 4,310 | | $ | 3,173 | |
12. Property, Plant and Equipment
Exploratory well costs capitalized greater than one year after completion of drilling as of June 30, 2007 were $119 million, including $24 million added to this category during the second quarter of 2007 for the Gudrun appraisal well offshore Norway, where Marathon and its partners are evaluating development scenarios with development concept selection expected in 2008.
13. Long-term Debt
On June 26, 2007, the Parish of St. John the Baptist, where Marathon’s Garyville, Louisiana, refinery is located, issued $1.0 billion of 5.125 percent Fixed Rate Revenue Bonds (Marathon Oil Corporation Project) Series 2007A associated with the Garyville refinery expansion with a maturity date of June 1, 2037. Following the issuance, the proceeds were trusteed and will be disbursed to Marathon upon the Company’s request for reimbursement of expenditures related to the Garyville refinery expansion. Marathon is solely obligated to service the principal and interest payments associated with the bonds. The $1.0 billion of trusteed funds are reflected as other noncurrent assets and the $1.0 billion obligation is reflected as long-term debt in the consolidated balance sheet as of June 30, 2007.
On June 15, 2007, Marathon borrowed $578 million under a loan agreement from Eksportfinans ASA, the Norwegian export credit agency, based upon the amount of qualifying purchases of goods and services by Marathon from Norwegian contractors. The original loan agreement that was executed in 2006 was amended in June 2007 to provide for an increase in borrowing capacity from $525 million to $578 million. The term of the loan is 8.5 years with semi-annual principal and interest payments beginning December 15, 2007, and the loan bears a fixed interest rate of 4.55 percent. The loan also requires additional credit security support in the form of letters of credit or guarantees.
Effective May 7, 2007, Marathon entered into an amendment to its $2.0 billion revolving credit agreement, extending the termination date from May 2011 to May 2012. At June 30, 2007, there were no borrowings against this facility.
14. Stock-Based Compensation Plans
The following is a summary of stock option award activity:
| | Number
of Shares | | Weighted
Average
Exercise Price | |
Outstanding at December 31, 2006 (a) | | 10,990,990 | | $ | 24.72 | |
Granted | | 3,045,800 | | $ | 61.05 | |
Exercised | | (1,252,232 | ) | $ | 20.72 | |
Canceled | | (105,986 | ) | $ | 30.19 | |
Outstanding at June 30, 2007 (b) | | 12,678,572 | | $ | 33.79 | |
(a) Restated for the June 18, 2007 two-for-one stock split, which was effected a through a stock dividend.
(b) Of the stock option awards outstanding as of June 30, 2007, 3,045,800, 8,997,502, and 635,270 were outstanding under the 2007 Incentive Compensation Plan, the 2003 Incentive Compensation Plan and the 1990 Stock Plan, including 814,782 stock options with tandem SARs.
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15. Commitments and Contingencies
Marathon is the subject of, or party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to Marathon’s consolidated financial statements. However, management believes that Marathon will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably. Certain of the Company’s commitments are discussed below.
Contract commitments – At June 30, 2007 and December 31, 2006, Marathon’s contract commitments to acquire property, plant and equipment totaled $2.505 billion and $1.703 billion. During the first six months of 2007, the majority of additional contract commitments were related to the expansion of the Company’s Garyville, Louisiana, refinery.
16. Share Repurchase Program
In January 2006, Marathon’s Board of Directors authorized the repurchase of up to $2 billion of common stock. The share repurchase program was extended by $500 million in January 2007, by an additional $500 million in May 2007, and by $2 billion in July 2007, for a total authorized program of $5 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. The Company will use cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon the Company’s financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables. As of June 30, 2007, the Company had acquired 57 million common shares at a cost of $2.474 billion under the program, including 15 million common shares acquired during the first six months of 2007 at a cost of $776 million.
17. Supplemental Cash Flow Information
| | Six Months Ended June 30, | |
(In millions) | | 2007 | | 2006 | |
Noncash investing and financing activities: | | | | | |
Bond obligation assumed for trusteed funds | | $ | 1,000 | | $ | — | |
| | | | | |
Noncash effect of deconsolidation of EGHoldings: | | | | | |
Decrease in non-cash assets | | $ | 1,759 | | $ | — | |
Record equity method investment | | 942 | | — | |
Decrease in liabilities | | 310 | | — | |
Elimination of minority interest | | 544 | | — | |
| | | | | |
Commercial paper and revolving credit arrangements, net: | | | | | |
Borrowings | | $ | — | | $ | 1,321 | |
Repayments | | — | | (1,321 | ) |
| | | | | |
Net cash provided from operating activities included: | | | | | |
Interest paid (net of amounts capitalized) | | $ | 20 | | $ | 56 | |
Income taxes paid to taxing authorities | | 1,630 | | 1,722 | |
18. Subsequent Event
In July 2007, Marathon entered an agreement to purchase Western Oil Sands Inc. (“Western”). Under the terms of the agreement, Western shareholders will receive cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock and securities exchangeable for Marathon common stock. Marathon will also assume Western’s debt at closing. The agreement requires Western to spin off a wholly-owned subsidiary with interests in the Federal Region of Kurdistan in northern Iraq prior to closing. The transaction is contingent upon Western shareholder approval and applicable regulatory approvals and is anticipated to close in the fourth quarter of 2007.
19. Accounting Standards Not Yet Adopted
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income. The statement also
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establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. For Marathon, SFAS No. 159 will be effective January 1, 2008, and retrospective application is not permitted. Should Marathon elect to apply the fair value option to any eligible items that exist at January 1, 2008, the effect of the first remeasurement to fair value would be reported as a cumulative effect adjustment to the opening balance of retained earnings. Marathon is currently evaluating the provisions of this statement.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices. For Marathon, SFAS No. 157 will be effective January 1, 2008. Marathon is currently evaluating the provisions of this statement.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Marathon Oil Corporation is engaged in worldwide exploration, production and marketing of crude oil and natural gas; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and worldwide marketing and transportation of products manufactured from natural gas, such as LNG and methanol, and development of other projects to link stranded natural gas resources with key demand areas. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Consolidated Financial Statements and Selected Notes to Consolidated Financial Statements, the Supplemental Statistics and our 2006 Annual Report on Form 10-K.
Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2006 Annual Report on Form 10-K.
Marathon holds a 60 percent interest in Equatorial Guinea LNG Holdings Limited (“EGHoldings”). The remaining interests are held by Sociedad Nacional de Gas de Guinea Equatorial (“SONAGAS”) (25 percent interest), Mitsui & Co., Ltd. (8.5 percent interest) and a subsidiary of Marubeni Corporation (6.5 percent interest). As discussed in Note 3 to the accompanying consolidated financial statements, effective May 1, 2007, we no longer consolidate EGHoldings. Our investment is accounted for prospectively using the equity method of accounting. Amounts presented for the Integrated Gas segment for periods prior to May 1, 2007 include amounts related to the minority interests, unless specifically noted as being after minority interests.
Overview and Outlook
Operational and Corporate Highlights
During the first six months of 2007, we:
· Announced the results of the Droshky discovery and two appraisal sidetrack wells in the Gulf of Mexico;
· Announced six exploration discoveries in deepwater Angola;
· Signed an agreement to carry out a study of the Dnieper-Donets Basin located in north central Ukraine;
· Continued to progress the Neptune development in deepwater Gulf of Mexico and the Alvheim/Vilje project in Norway;
· Commenced construction of the Garyville, Louisiana, refinery expansion;
· Set records for refinery crude and total throughputs for the first six months of the year;
· Continued construction of the 110 million gallon per year joint venture ethanol facility in Greenville, Ohio;
· Commenced production at the Equatorial Guinea LNG production facility and delivered three shipments of LNG;
· Repurchased 15 million common shares, bringing total stock repurchases to date to 57 million shares at a cost of $2.474 billion;
· Increased our quarterly dividend per share by 20 percent; and
· Completed a two-for-one split of our common stock.
Exploration and Production (“E&P”)
Net liquid hydrocarbon and natural gas sales during the second quarter and first six months of 2007 averaged 338 and 339 thousand barrels of oil equivalent per day (“mboepd”).
During the first six months of 2007, we announced the Droshky discovery well and the results of two appraisal sidetrack wells. The discovery is located on Green Canyon Block 244 in the Gulf of Mexico (previously named Troika Deep). The timing of initial production from Droshky will be dependent upon delivery of key equipment (i.e., drilling rig and subsea equipment) and regulatory approvals, but could be as early as 2010. We hold a 100 percent working interest in the Droshky discovery.
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During the first six months of 2007, we also announced six exploration successes in deepwater Angola. The Caril, Manjericao, Cominhos and Louro discovery wells are located on Block 32, where we hold a 30 percent outside-operated interest, and the Miranda and Cordelia discovery wells are located on Block 31, where we hold a 10 percent outside-operated interest. These discoveries move both deepwater Angola blocks closer toward establishment of commercial developments. We had three dry wells in deepwater Angola during the second quarter of 2007 and we have also participated in two wells that have reached total depth, the results of which will be announced upon approval of the Angola government and our partners.
The Neptune development in the Gulf of Mexico continues to progress. The mini-tension leg platform hull was installed and topside facilities were set in June 2007. Subsea equipment installation, connection of surface equipment on the platform and facility commissioning are in progress. First production is anticipated by early 2008.
In Norway, the commissioning of the Alvheim floating production, storage and offloading (“FPSO”) vessel continues. Difficult market conditions for skilled labor and additional work to bring the FPSO into compliance with Norwegian codes and regulations and to fully integrate the existing ship systems with the new topside facilities has delayed expected first production to the fourth quarter of 2007. These factors, together with additional drilling activity, have contributed to increased costs for the project.
We now expect 2007 production available for sale to be between 350 and 375 mboepd, excluding the impact of acquisitions and dispositions, due to the delay in first production from the Alvheim/Vilje development. Previously we had expected production available for sale in 2007 to be between 390 and 425 mboepd. Sales volumes may vary from production available for sale due to the timing of liquid hydrocarbon liftings and natural gas sales.
The above discussion includes forward-looking statements with respect to the possibility of developing the Droshky discovery in the Gulf of Mexico and Blocks 31 and 32 offshore Angola, the Neptune and the Alvheim/Vilje development projects and the timing and levels of our worldwide liquid hydrocarbon, natural gas and condensate production available for sale. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. Except for the Alvheim/Vilje and Neptune developments, the foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits. The possible developments of Droshky and Blocks 31 and 32 could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. Worldwide production available for sale could also be affected by the occurrence of acquisitions or dispositions of oil and gas properties. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Refining, Marketing and Transportation (“RM&T”)
In the second quarter and first six months of 2007, our total refinery throughput was three percent and four percent higher than the same periods of 2006. Crude oil throughput was three percent and five percent higher in these periods and we expect crude oil throughput for the full year 2007 to exceed the record level we set in 2006. Our refining and wholesale marketing gross margin averaged 39.25 cents per gallon in the second quarter of 2007 compared to 29.78 cents per gallon in the second quarter of 2006. This margin improvement was consistent with the relevant market indicators in the Midwest and Gulf Coast markets. The increase in our refining and wholesale marketing gross margin for the first six months of 2007 was also impacted by the change in accounting for matching buy/sell arrangements effective April 1, 2006, as the sales volumes recognized in the first six months of 2007 were less than the volumes that would have been recognized under previous accounting practices. Our ethanol blending program increased to 40 thousand barrels per day (“mbpd”) in the second quarter of 2007 from 35 mbpd in the second quarter of 2006. The future expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply and government regulations.
Speedway SuperAmerica LLC (“SSA”) increased same store merchandise sales three percent and same store gasoline sales volumes one percent when compared to the second quarter of 2006. In addition SSA’s gasoline and distillates gross margin per gallon and merchandise gross margin were stronger in the second quarter and first six months of 2007 than in the comparable periods of 2006.
Construction of the Garyville, Louisiana, refinery commenced on schedule in early March 2007. Construction crews are clearing the site and driving piles that will be used to support the foundation for the equipment that will be constructed at this site over the next two years.
The above discussion includes forward-looking statements with respect to projections of crude oil throughput and ethanol blending that could be affected by planned and unplanned refinery maintenance projects, the levels of refining margins, other operating considerations and government regulations. The above discussion also contains forward-
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looking information with respect to the Garyville expansion project. Factors that could affect that project include crude oil supply, transportation logistics, availability of material and labor, unforeseen hazards such as weather conditions, necessary government and third party approvals, and other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Integrated Gas (“IG”)
The LNG production facility in Equatorial Guinea was completed and delivered its first cargo of LNG in May 2007. A total of three cargos were delivered during the second quarter of 2007. As scheduled, the production facility was shutdown in June 2007 for a performance test which confirmed the facility’s capacity of 3.7 million metric tonnes per annum. The facility was shut down again in July for commissioning maintenance and has since returned its processing levels to full capacity.
Once the LNG production facility commenced its primary operations and began to generate revenue in May 2007, EGHoldings was no longer a variable interest entity. Effective May 1, 2007, we no longer consolidate EGHoldings, despite the fact that we hold majority ownership, because the minority shareholders have rights limiting our ability to exercise control over the entity. Our investment in EGHoldings is accounted for prospectively using the equity method of accounting.
Together with our project partners, we have completed those portions of the front-end engineering and design for a potential second LNG production facility on Bioko Island, Equatorial Guinea that are required to support the near-term efforts for this project. We expect a final investment decision in 2008.
The above discussion contains forward-looking statements with respect to the possible expansion of the LNG production facility. Factors that could potentially affect the possible expansion of the facility and the development of additional LNG capacity through additional projects include partner approvals, access to sufficient natural gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Capital, Investment and Exploration Budget
We have increased our capital, investment and exploration budget for 2007, excluding major acquisitions, from $4.242 billion to $4.683 billion, which includes budgeted capital expenditures of $4.295 billion. Total E&P spending is now projected to be $2.614 billion, an increase of $383 million. This increase is approximately evenly divided between an increase in the cost of the Alvheim/Vilje development and general inflationary pressures. RM&T spending is expected to increase by $202 million to $1.666 billion, largely due to acceleration of certain aspects of the Garyville refinery expansion, while the projected total cost for the Garyville expansion remains unchanged at $3.2 billion. Integrated gas spending is now expected to be $209 million less than the original estimate of $331 million, reflecting EGHoldings being accounted for under the equity method upon start of production. Capitalized interest and corporate spending is expected to be $65 million higher than originally anticipated as a result of the delay of the Alvheim/Vilje project.
The forward-looking statements about our capital, investment and exploration budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.
Proposed Acquisition
In July 2007, we entered an agreement to purchase Western Oil Sands Inc. (“Western”). Under the terms of the agreement, Western shareholders will receive cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock and securities exchangeable for Marathon common stock. We will also assume Western’s debt at closing. Based on the exchange rate and our stock price on July 27, 2007, the total transaction value would be approximately $6 billion. The agreement requires Western to spin off a wholly-owned subsidiary with interests in the Federal Region of Kurdistan in northern Iraq prior to closing. The transaction is contingent upon Western shareholder approval and applicable regulatory approvals and is anticipated to close in the fourth quarter of 2007.
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Western’s primary asset is a 20 percent outside-operated interest in the Athabasca Oil Sands Project, which includes the operating Muskeg River Mine and the Scotford Upgrader, located in the province of Alberta, Canada. Western’s current net bitumen production from the Muskeg River Mine is approximately 31 mbpd. The bitumen production from the Muskeg River Mine is taken by pipeline to the Scotford Upgrader, which uses hydro-conversion technology to upgrade the bitumen into a range of high-quality, synthetic crude oils. A key attribute of this proposed acquisition is the ability to link future production from the Athabasca Oil Sands Project developments with heavy oil upgrade projects at our refineries.
The above discussion contains forward-looking statements concerning the anticipated acquisition of Western and potential heavy oil refining upgrading projects. This forward-looking information may prove to be inaccurate and actual results may differ materially from those presently anticipated. Factors, but not necessarily all factors, that could adversely affect the anticipated acquisition of Western include the inability or delay in obtaining necessary government and third-party approvals and approval by Western’s shareholders. Factors that could affect the potential heavy oil refining upgrading projects include results of front-end engineering and design work, approval of our Board of Directors, inability or delay in obtaining necessary government and third-party approvals, continued favorable investment climate, and other geological, operating and economic considerations.
Corporate
On April 25, 2007, our Board of Directors declared a two-for-one split of our common stock. The stock split was effected in the form of a stock dividend distributed on June 18, 2007, to stockholders of record at the close of business on May 23, 2007. Stockholders received one additional share of our common stock for each share of common stock held as of the close of business on the record date. Common share and per share (except par value) information for all periods presented has been restated throughout this Quarterly Report on Form 10-Q to reflect the stock split.
Critical Accounting Estimates
The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used.
Certain accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material.
There have been no significant changes to our critical accounting estimates subsequent to December 31, 2006.
Management’s Discussion and Analysis of Results of Operations
Change in Accounting for Matching Buy/Sell Transactions
Matching buy/sell transactions arise from arrangements in which we agree to buy a specified quantity and quality of crude oil or refined product to be delivered to a specified location while simultaneously agreeing to sell a specified quantity and quality of the same commodity at a specified location to the same counterparty. Prior to April 1, 2006, all matching buy/sell transactions were recorded as separate sale and purchase transactions, or on a “gross” basis. Effective for contracts entered into or modified on or after April 1, 2006, the income effects of matching buy/sell transactions are reported in cost of revenues, or on a “net” basis, based on an accounting interpretation which clarified the circumstances under which a matching buy/sell transaction should be viewed as a single transaction involving the exchange of inventory. Transactions under contracts entered into before April 1, 2006 will continue to be reported on a “gross” basis. This accounting change had no effect on net income but the amounts of revenues and cost of revenues recognized after April 1, 2006 are less than the amounts that would have been recognized under previous accounting practices.
Additionally, this accounting change impacts the comparability of certain operating statistics, most notably “refining and wholesale marketing gross margin per gallon.” While this change does not have an effect on the refining and wholesale marketing gross margin (the numerator for calculating this statistic), sales volumes (the denominator for calculating this statistic) recognized after April 1, 2006 are less than the amount that would have been recognized under previous accounting practices because volumes related to matching buy/sell transactions under contracts entered into or modified on or after April 1, 2006 have been excluded. Accordingly, the resulting refining and wholesale marketing gross margin per gallon statistic will be higher than that same statistic calculated from amounts determined under previous accounting practices.
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As a result, this accounting change impacts the comparability of revenues, cost of revenues and the refining and wholesale marketing gross margin per gallon for the first six months of 2007 and 2006.
Consolidated Results of Operations
Revenues for the second quarters and first six months of 2007 and 2006 are summarized by segment in the following table:
| | Second Quarter Ended | | Six Months Ended | |
| | June 30, | | June 30, | |
(In millions) | | 2007 | | 2006 | | 2007 | | 2006 | |
E&P | | $ | 2,141 | | $ | 2,515 | | $ | 3,990 | | $ | 4,816 | |
RM&T | | 14,735 | | 15,800 | | 25,819 | | 30,012 | |
IG | | 68 | | 70 | | 124 | | 100 | |
| | | | | | | | | |
Segment revenues | | 16,944 | | 18,385 | | 29,933 | | 34,928 | |
Elimination of intersegment revenues | | (199 | ) | (189 | ) | (340 | ) | (392 | ) |
Gain (loss) on long-term U.K. natural gas contracts | | (9 | ) | (17 | ) | 12 | | 61 | |
| | | | | | | | | |
Total revenues | | $ | 16,736 | | $ | 18,179 | | $ | 29,605 | | $ | 34,597 | |
| | | | | | | | | |
Items included in both revenues and costs and expenses: | | | | | | | | | |
| | | | | | | | | |
Consumer excise taxes on petroleum products and merchandise | | $ | 1,307 | | $ | 1,277 | | $ | 2,504 | | $ | 2,442 | |
Matching crude oil and refined product buy/sell transactions: | | | | | | | | | |
| | | | | | | | | |
E&P | | — | | 5 | | — | | 16 | |
RM&T | | 65 | | 1,801 | | 123 | | 4,996 | |
| | | | | | | | | |
Total buy/sell transactions included in revenues | | $ | 65 | | $ | 1,806 | | $ | 123 | | $ | 5,012 | |
E&P segment revenues decreased $374 million in the second quarter of 2007 from the comparable prior-year period, primarily as a result of lower liquid hydrocarbon sales volumes and realizations, with the most significant sales volume decline related to international operations. International liquid hydrocarbon sales volumes were significantly higher in the second quarter of 2006 due to approximately 40 mbpd of sales in excess of production in that quarter, while sales volumes approximated production in the second quarter of 2007. Though it did not have a significant impact on E&P segment revenues, the increase in Equatorial Guinea natural gas sales volumes due to the start-up of the LNG production facility there contributed to the decline in the average international natural gas realization for the second quarter of 2007.
E&P segment revenues in the first six months of 2007 decreased $826 million from the comparable prior-year period. Revenue decreases from natural gas marketing activities in the first quarter of 2007 account for a substantial portion of the decline for the six-month period. The remainder of the decrease was primarily related to lower liquid hydrocarbon and natural gas sales volumes and realizations. Normal production rate declines, particularly for our Gulf of Mexico properties, caused domestic liquid hydrocarbon and natural gas sales volumes to decrease in the first six months of 2007 compared to the same period of 2006.
See Supplemental Statistics for information regarding net sales volumes and average realizations by geographic area.
Excluded from E&P segment revenues were losses of $9 million and $17 million for the second quarters of 2007 and 2006, on long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments. For the first six months of 2007 and 2006, gains of $12 million and $61 million are excluded from E&P segment revenues. See Item 3. Quantitative and Qualitative Disclosures About Market Risk.
RM&T segment revenues decreased $1.065 billion in the second quarter of 2007 and $4.193 billion in the first six months of 2007 from the comparable prior-year periods primarily as a result of the change in accounting for matching buy/sell transactions effective April 1, 2006, discussed above. Excluding matching buy/sell transactions, RM&T segment
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revenues increased in both periods, reflecting increased refined product selling prices and crude oil sales volumes, partially offset by lower refined product sales volumes.
For information on segment income, see Segment Results.
Purchases related to matching buy/sell transactions decreased $1.666 billion and $4.838 billion in the second quarter and first six months of 2007 from the comparable prior-year periods as a result of the change in accounting for matching buy/sell transactions effective April 1, 2006, discussed above.
Exploration expenses were $115 million and $176 million in the second quarter and first six months of 2007, including expenses related to dry wells of $39 million and $55 million primarily related to exploration activities in Angola. Exploration expenses were $66 million and $137 million in the second quarter and first six months of 2006, including expenses related to dry wells of $28 million and $58 million. The largest increase in exploration expenses in these periods related to geological and geophysical costs.
Provision for income taxes decreased $47 million and $114 million in the second quarter and first six months of 2007 from the comparable periods of 2006 as a result of effective tax rate declines in both periods and the $110 million decrease in income from continuing operations before income taxes for the six-month period. The following is an analysis of the effective income tax rates for continuing operations for the second quarters and first six months of 2007 and 2006:
| | Second Quarter Ended
June 30, | | Six Months Ended
June 30, | |
| | 2007 | | 2006 | | 2007 | | 2006 | |
Statutory U.S. income tax rate | | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % |
Effects of foreign operations, including foreign tax credits | | 8.4 | | 9.9 | | 9.2 | | 10.4 | |
State and local income taxes, net of federal income tax effects | | 2.2 | | 2.0 | | 2.1 | | 2.0 | |
Other tax effects | | (1.1 | ) | (0.6 | ) | (1.3 | ) | (0.8 | ) |
Effective income tax rate for continuing operations | | 44.5 | % | 46.3 | % | 45.0 | % | 46.6 | % |
Discontinued operations in 2006 reflects the operations of our Russian oil exploration and production businesses and a $243 million after-tax gain related to the June 2006 disposal of these businesses. During the second quarter of 2007, adjustments to the sales price were substantially completed and an additional after-tax gain on the sale of $8 million was recognized. See Note 5 to the accompanying consolidated financial statements for additional information.
Segment Results
Segment income for the second quarters and first six months of 2007 and 2006 is summarized in the following table.
| | Second Quarter Ended | | Six Months Ended | |
| | June 30, | | June 30, | |
(In millions) | | 2007 | | 2006 | | 2007 | | 2006 | |
E&P | | | | | | | | | |
United States | | $ | 173 | | $ | 243 | | $ | 323 | | $ | 488 | |
International | | 227 | | 416 | | 462 | | 636 | |
| | | | | | | | | |
E&P segment | | 400 | | 659 | | 785 | | 1,124 | |
RM&T | | 1,246 | | 917 | | 1,591 | | 1,236 | |
IG | | 12 | | 17 | | 31 | | 25 | |
| | | | | | | | | |
Segment income | | 1,658 | | 1,593 | | 2,407 | | 2,385 | |
Items not allocated to segments, net of income taxes: | | | | | | | | | |
Corporate and other unallocated items | | (111 | ) | (99 | ) | (154 | ) | (165 | ) |
Gain (loss) on long-term U.K. natural gas contracts | | (5 | ) | (10 | ) | 6 | | 35 | |
Discontinued operations | | 8 | | 264 | | 8 | | 277 | |
| | | | | | | | | |
Net income | | $ | 1,550 | | $ | 1,748 | | $ | 2,267 | | $ | 2,532 | |
United States E&P income decreased $70 million, or 29 percent, in the second quarter of 2007 and decreased $165 million, or 34 percent, in the first six months of 2007 compared to the same periods of 2006. Pretax income decreased $126 million and $276 million in the same periods and the effective income tax rate decreased to 34 percent from 37
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percent in the second quarter of 2006. The lower pretax income is primarily a result of revenue decreases from lower liquid hydrocarbon and natural gas sales volumes and liquid hydrocarbon realizations, as discussed above.
International E&P income decreased $189 million, or 45 percent, and $174 million, or 27 percent, in the second quarter and first six months of 2007 compared to the same periods of 2006. Pretax income decreased $369 million and $365 million in the same periods, while the effective income tax rate increased from 58 percent to 63 percent in the second quarter of 2007 and from 59 percent to 61 percent in the first six months of 2007 compared to the 2006 periods. The lower pretax income is primarily a result of revenue decreases from lower liquid hydrocarbon sales volumes and lower liquid hydrocarbon and natural gas realizations, as discussed above, and increased exploration expenses, including dry well costs in Angola and geological and geophysical costs.
RM&T segment income increased by $329 million, or 36 percent, and $355 million, or 29 percent, in the second quarter and first six months of 2007 compared to the same periods of 2006. Pretax income increased $486 million and $506 million in the same periods, while the effective income tax rate decreased slightly in both periods. The increases in RM&T pretax income are primarily a result of improvement in the refining and wholesale marketing gross margin, which averaged 39.25 cents per gallon in the second quarter of 2007 and 26.34 cents per gallon in the first six months of 2007, compared to 29.78 cents per gallon and 20.77 cents per gallon in the comparable periods of 2006. This margin improvement was consistent with the relevant market indicators in the Midwest and Gulf Coast markets. Crude oil refined averaged 1,072 mbpd and 1,021 mbpd, during the second quarter and first six months of 2007, 34 mbpd and 53 mbpd higher than the averages for the same periods of 2006.
IG segment income decreased $5 million in the second quarter of 2007 and increased $6 million in the first six months of 2007 compared to the same periods of 2006. Increased income from EGHoldings, as a result of the first LNG deliveries during the second quarter of 2007, was more than offset by a decline in income from domestic integrated gas activities due to a planned turnaround at our LNG production facility in Alaska, increased research and development costs and increased income taxes. Contributing to improved results for the first six months of 2007 was higher income from Atlantic Methanol Production Company LLC in the first quarter of 2007 due to higher realized methanol prices.
Management’s Discussion and Analysis of Cash Flows and Liquidity
Cash Flows
Net cash provided from operating activities totaled $2.366 billion in the first six months of 2007, compared to $2.299 billion in the first six months of 2006.
Net cash used in investing activities totaled $1.728 billion in the first six months of 2007, compared to $857 million in the first six months of 2006. Capital expenditures were $1.699 billion compared with $1.308 billion for the comparable prior-year period, with the increased spending primarily related to the Garyville refinery expansion in the RM&T segment and the Neptune development in the E&P segment. See Supplemental Statistics for information regarding capital expenditures by segment. Investing activities for the first six months of 2006 also included net cash proceeds of $832 million from the sale of our Russian oil exploration and production businesses in June 2006 and cash paid for acquisitions of $543 million, primarily related to the initial $520 million payment associated with our re-entry into Libya.
Net cash used in financing activities was $896 million in the first six months of 2007, compared to $1.048 billion in the first six months of 2006. Significant uses of cash in financing activities during both periods included stock repurchases, repayments of maturing debt and dividend payments. Financing activities for the second quarter of 2007 included borrowings of $578 million from the Norwegian export credit agency.
Dividends to Stockholders
On July 25, 2007, our Board of Directors declared a dividend of 24 cents per share, payable September 10, 2007, to stockholders of record at the close of business on August 16, 2007.
Derivative Instruments
See Quantitative and Qualitative Disclosures About Market Risk for a discussion of derivative instruments and associated market risk.
Liquidity and Capital Resources
Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed credit facilities and access to both the debt and equity capital markets. Our ability to access the debt capital market is
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supported by our investment grade credit ratings. Our senior unsecured debt is currently rated investment grade by Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings with ratings of BBB+, Baa1 and BBB+. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending programs, stock repurchase program, repayment of debt maturities, the proposed acquisition of Western and any amounts that may ultimately be paid in connection with contingencies.
We have a committed $2.0 billion revolving credit facility with third-party financial institutions terminating in May 2012. At June 30, 2007, there were no borrowings against this facility and we had no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
On June 26, 2007, the Parish of St. John the Baptist, where our Garyville, Louisiana, refinery is located, issued $1.0 billion of 5.125 percent Fixed Rate Revenue Bonds (Marathon Oil Corporation Project) Series 2007A associated with the Garyville refinery expansion, with a maturity date of June 1, 2037. Following the issuance, the proceeds were trusteed and will be disbursed to us upon our request for reimbursement of expenditures related to the Garyville refinery expansion. We are solely obligated to service the principal and interest payments associated with the bonds. The $1.0 billion of trusteed funds are reflected as other noncurrent assets and the $1.0 billion obligation is reflected as long-term debt in the consolidated balance sheet as of June 30, 2007.
On June 15, 2007, we borrowed $578 million under a loan agreement from Eksportfinans ASA, the Norwegian export credit agency, based upon the amount of qualifying purchases of goods and services by us from Norwegian contractors. The original loan agreement that was executed in 2006 was amended in June 2007 to provide for an increase in borrowing capacity from $525 million to $578 million. The term of the loan is 8.5 years with semi-annual principal and interest payments beginning December 15, 2007, and the loan bears a fixed interest rate of 4.55 percent. The loan also requires additional credit security support in the form of letters of credit or guarantees.
Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and trusteed funds to total debt-plus-equity-minus-cash and trusteed funds) was eight percent at June 30, 2007, compared to six percent at year-end 2006 as shown below. This includes $510 million of debt that is serviced by United States Steel Corporation (“United States Steel”).
(Dollars in millions) | | June 30,
2007 | | December 31,
2006 | |
Long-term debt due within one year | | $ | 421 | | $ | 471 | |
Long-term debt | | 4,237 | | 3,061 | |
Total debt | | $ | 4,658 | | $ | 3,532 | |
Cash | | $ | 2,331 | | $ | 2,585 | |
Trusteed funds from revenue bonds (a) | | $ | 1,000 | | $ | — | |
Equity | | $ | 15,815 | | $ | 14,607 | |
Calculation: | | | | | |
Total debt | | $ | 4,658 | | $ | 3,532 | |
Minus cash | | 2,331 | | 2,585 | |
Minus trusteed funds from revenue bonds | | 1,000 | | — | |
Total debt minus cash | | 1,327 | | 947 | |
| | | | | |
Total debt | | 4,658 | | 3,532 | |
Plus equity | | 15,815 | | 14,607 | |
Minus cash | | 2,331 | | 2,585 | |
Minus trusteed funds from revenue bonds | | 1,000 | | — | |
Total debt plus equity minus cash | | $ | 17,142 | | $ | 15,554 | |
Cash-adjusted debt-to-capital ratio | | 8 | % | 6 | % |
(a) Following the issuance of the $1.0 billion of revenue bonds by the Parish of St. John the Baptist, the proceeds were trusteed and will be disbursed to us upon our request for reimbursement of expenditures related to the issuance of the bonds or the Garyville refinery expansion. The trusteed funds are reflected as other noncurrent assets in the accompanying consolidated balance sheet as of June 30, 2007.
In July 2007, we entered an agreement to purchase Western. Under the terms of the agreement, Western shareholders will receive cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock and securities exchangeable for Marathon common stock. We will also assume Western’s debt at closing. Based on the exchange rate and our stock price on July 27, 2007, the total transaction value would be approximately $6 billion. The agreement requires Western to spin off a wholly-owned subsidiary with interests in the Federal Region of Kurdistan in northern Iraq prior to closing. The transaction is contingent upon Western shareholder approval and applicable regulatory approvals and is anticipated to close in the fourth quarter of 2007. If we complete this proposed acquisition, we expect our cash-adjusted debt-to-capital ratio will be in the mid-20 percent range. We anticipate funding the cash
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portion of the acquisition with cash on hand, short-term credit facilities and new long-term borrowings. Following the announcement of the transaction, Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings each affirmed our current senior unsecured debt ratings.
On July 26, 2007, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The above discussion also contains forward-looking statements concerning the anticipated acquisition of Western. This forward-looking information may prove to be inaccurate and actual results may differ materially from those presently anticipated. Factors, but not necessarily all factors, that could adversely affect the anticipated acquisition include the inability or delay in obtaining necessary government and third-party approvals and approval by Western’s shareholders.
Stock Repurchase Program
Our Board of Directors has authorized a common stock repurchase program totaling $5 billion, with $500 million added to the program in May 2007 and $2 billion added to the program in July 2007. As of June 30, 2007, we had repurchased 57 million common shares at a cost of $2.474 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. We will use cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program does not include specific price targets or timetables.
The forward-looking statements about our common stock repurchase program are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.
Contractual Cash Obligations
As of June 30, 2007, our contractual cash obligations have increased by $2.859 billion from December 31, 2006. Our purchase obligations under crude oil, refinery feedstock, refined product and ethanol contracts, which are primarily short-term, increased $1.226 billion primarily related to refined products. Long-term debt increased by $1.130 billion due to the revenue bond issuance and Norwegian borrowings in the second quarter of 2007 discussed above, net of the repayment of maturing debt. Otherwise, there have been no significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2006. The portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel has not changed significantly subsequent to December 31, 2006.
Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on our liquidity and capital resources. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2006.
Nonrecourse Indebtedness of Investees
Certain of our investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been $339 million as of June 30,
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2007. Of this amount, $217 million relates to Pilot Travel Centers LLC (“PTC”). If any of these investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $75 million of the total PTC debt.
Obligations Associated with the Separation of United States Steel
We remain obligated (primarily or contingently) for certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment under the terms of the Separation. (See the discussion of the Separation in our 2006 Annual Report on Form 10-K.) United States Steel’s obligations to Marathon are general unsecured obligations that rank equal to United States Steel’s accounts payable and other general unsecured obligations. If United States Steel fails to satisfy these obligations, we would become responsible for repayment. Under the Financial Matters Agreement, United States Steel has all of the existing contractual rights under the leases assumed from Marathon, including all rights related to purchase options, prepayments or the grant or release of security interests. However, United States Steel has no right to increase amounts due under or lengthen the term of any of the assumed leases, other than extensions set forth in the terms of the assumed leases.
As of June 30, 2007, we have obligations totaling $549 million that have been assumed by United States Steel. Of this amount, obligations of $519 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion - $31 million; long-term portion - $488 million). The remaining $30 million was related to off-balance sheet arrangements and contingent liabilities of United States Steel.
Environmental Matters
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil, refined products and feedstocks.
Air
The U.S. Environmental Protection Agency (“EPA”) is in the process of implementing regulations to address current National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. To address these nonattainment areas, the EPA proposed a rule in 2004 called the Interstate Air Quality Rule (“IAQR”) that would require significant emissions reductions in numerous states. The final rule, promulgated in 2005, was renamed the Clean Air Interstate Rule (“CAIR”). While the EPA expects that states will meet their CAIR obligations by requiring emissions reductions from electric generating units, states will have the final say on what sources they regulate to meet attainment criteria. Our refinery operations are located in affected states and some of these states may choose to propose more stringent fuels requirements to meet the CAIR. Also, on July 11, 2007, the EPA proposed a revised ozone standard. Once the revised ozone standard is promulgated, the EPA will begin the multi-year process to develop the implementing rules required by the Clean Air Act. We cannot reasonably estimate the final financial impact of the state actions to implement the CAIR until the states have taken further action and we cannot reasonably estimate the final financial impact of the revised ozone standard until the implementing rules are established.
We now plan to spend approximately $350 million from 2006 through 2010 on refinery investments to produce ultra-low sulfur diesel fuel for off-road use, in compliance with previously disclosed EPA regulations that require reduced sulfur levels for diesel fuel.
Wyoming Proceedings
In response to the Governor of Wyoming’s veto of a state agency adoption of a rule that would allow the State Department of Environmental Quality (“DEQ”) to regulate the quantity of coal bed methane water discharges, an activist group has sued in State Court to overturn the veto. In June 2007, Marathon and another producer filed a motion to intervene. The State DEQ has begun issuing renewal water discharge and other permits with stringent limits based on its agricultural use policy rather than upon any regulation. The permits could require more costly water treatment or injection. Marathon is appealing every permit issued in this way as unlawful.
MTBE Litigation
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We are a defendant, along with many other companies with refining operations, in over 50 cases in 12 states alleging methyl tertiary-butyl ether (“MTBE”) contamination in groundwater. There have been two recent developments in these matters. The federal Second Circuit Court of Appeals ruled in two of the MTBE cases brought by the states of New Hampshire and California (Marathon was not a party in these cases.) that the cases had been improperly removed to federal court based upon federal officer jurisdiction. The parties are briefing to the court whether other grounds for federal jurisdiction exist. If federal jurisdiction is found to be not proper in these cases, the issue of federal jurisdiction may then be raised in all of the MTBE cases. If removal is found to be improper in any case, it would be returned to state court. Also, the state of New Jersey has recently sued Marathon and the other refiners. This is the only case Marathon is involved with which has a state as a plaintiff and it is the only case where natural resources damages are sought. We continue to defend all of these MTBE cases vigorously.
Environmental Proceedings
In the Environmental Defense Fund (“EDF”) v. Bureau of Land Management (“BLM”) case before the Federal District Court of Wyoming, the EDF alleged that in 2002, the BLM did not sufficiently evaluate the air impacts associated with coal bed natural gas production in the Powder River Basin, as well as other oil and gas operations in Wyoming. Marathon and other producers had intervened. In June 2007, the Federal District Court for the District of Wyoming dismissed the EDF case (without prejudice as to refiling).
Other Proceedings
Marathon resolved the enforcement action brought by the Minnesota Pollution Control Agency (“MPCA”) in 2007 regarding a release of catalyst from the fluid catalytic cracking unit at the St. Paul Park, Minnesota, refinery for a civil penalty of $60,000. MPCA had originally sought a penalty of $121,800.
The United States Occupational, Safety, and Health Administration (“OSHA”) has announced a National Emphasis Program (“NEP”) where it plans to inspect most of the domestic oil refinery locations in 2007 and 2008. The inspections will focus on compliance with the OSHA Process Safety Management requirements and may take several weeks or months to conduct. OSHA commenced an inspection at Marathon’s Canton, Ohio, refinery in the second quarter of 2007. Some enforcement actions by OSHA under the NEP against domestic petroleum refiners may result from the inspections but there is no specific enforcement action against Marathon at this time.
There have been no other significant changes to our environmental matters subsequent to December 31, 2006.
Other Contingencies
We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to us. However, we believe that we will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably to us. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.
Accounting Standards Not Yet Adopted
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income. The statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. For us, SFAS No. 159 will be effective January 1, 2008, and retrospective application is not permitted. Should we elect to apply the fair value option to any eligible items that exist at January 1, 2008, the effect of the first remeasurement to fair value would be reported as a cumulative effect adjustment to the opening balance of retained earnings. We are currently evaluating the provisions of this statement.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices. For us, SFAS No. 157 will be effective January 1, 2008. We are currently evaluating the provisions of this statement.
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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
Management Opinion Concerning Derivative Instruments
Management has authorized the use of futures, forwards, swaps and combinations of options to manage exposure to market fluctuations in commodity prices, interest rates and foreign currency exchange rates.
We use commodity-based derivatives to manage price risk related to the purchase, production or sale of crude oil, natural gas and refined products. To a lesser extent, we use commodity-based derivatives to mange our exposure to the risk of price fluctuations on natural gas liquids and petroleum feedstocks used as raw materials, and on purchases of ethanol.
Our strategy has generally been to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of derivative instruments, including option combinations, as part of the overall risk management program to manage commodity price risk in our different businesses. As market conditions change, we evaluate our risk management program and could enter into strategies that assume market risk.
Our E&P segment primarily uses commodity derivative instruments selectively to protect against price decreases on portions of our future production when deemed advantageous to do so. We also use derivatives to protect the value of natural gas purchased and injected into storage in support of production operations. We use commodity derivative instruments to mitigate the price risk associated with the purchase and subsequent resale of natural gas on purchased volumes and anticipated sales volumes.
Our RM&T segment uses commodity derivative instruments:
· to mitigate the price risk:
· between the time foreign and domestic crude oil and other feedstock purchases for refinery supply are priced and when they are actually refined into salable petroleum products,
· on fixed price contracts for ethanol purchases,
· associated with anticipated natural gas purchases for refinery use, and
· associated with freight on crude oil, feedstocks and refined product deliveries;
· to protect the value of excess refined product, crude oil and liquefied petroleum gas inventories;
· to protect margins associated with future fixed price sales of refined products to non-retail customers;
· to protect against decreases in future crack spreads; and
· to take advantage of trading opportunities identified in the commodity markets.
We use financial derivative instruments to manage certain interest rate exposures and foreign currency exchange rate exposures on certain foreign currency denominated capital expenditures, operating expenses and tax payments.
We believe that our use of derivative instruments, along with risk assessment procedures and internal controls, does not expose us to material risk. However, the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods. We believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.
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Commodity Price Risk
Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changes in commodity prices for open commodity derivative instruments as of June 30, 2007 are provided in the following table:
| | Incremental Decrease in IFO Assuming a
Hypothetical Price Change of (a): | |
(In millions) | | 10% | | 25% | |
Commodity Derivative Instruments: (b)(c) | | | | | |
Crude oil (d) | | $ | — | | $ | — | |
Natural gas (d) | | 40 | (e) | 100 | (e) |
Refined products (d) | | 20 | (e) | 61 | (e) |
| | | | | | | |
(a) We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the sensitivity analysis. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at June 30, 2007. Included in the natural gas impacts shown above are $44 million and $111 million related to the long-term U.K. natural gas contracts accounted for as derivative instruments for hypothetical price changes of 10 percent and 25 percent. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after June 30, 2007, would cause future IFO effects to differ from those presented in the table.
(b) The number of net open contracts for the E&P segment varied throughout the second quarter of 2007, from a low of 15 contracts on April 30, 2007, to a high of 782 contracts on April 1, 2007, and averaged 322 for the quarter. The number of net open contracts for the RM&T segment varied throughout the second quarter of 2007, from a low of 982 contracts on April 17, 2007 to a high of 21,633 contracts on June 27, 2007, and averaged 11,864 for the quarter. The derivative commodity instruments used and positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.
(c) The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.
(d) The direction of the price change used in calculating the sensitivity amount for each commodity reflects that which would result in the largest incremental decrease in IFO when applied to the commodity derivative instruments used to hedge that commodity.
(e) Price increase.
E&P Segment
Derivative losses of $24 million and gains of $24 million were included in E&P segment income for the first six months of 2007 and 2006, and were primarily related to derivatives utilized to protect the value of natural gas in storage and margins on natural gas purchases for resale. Excluded from E&P segment income were gains of $12 million and $61 million for the first six months of 2007 and 2006 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.
At June 30, 2007, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore we remain exposed to market prices of commodities. We continue to evaluate the commodity price risks related to our production and may enter into derivative commodity instruments when it is deemed advantageous. As a particular but not exclusive example, we may elect to use commodity derivative instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.
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RM&T Segment
We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize in net income all changes in the fair value of derivatives used in our RM&T operations. Pretax derivative gains and losses included in RM&T segment income for the second quarters and first six months of 2007 and 2006 are summarized in the following table:
| | Second Quarter Ended
June 30, | | Six Months Ended
June 30, | |
(In millions) | | 2007 | | 2006 | | 2007 | | 2006 | |
| | | | | | | | | |
Strategy: | | | | | | | | | |
Mitigate price risk | | $ | (71 | ) | $ | (109 | ) | $ | (19 | ) | $ | (105 | ) |
Protect carrying values of excess inventories | | (51 | ) | (62 | ) | (76 | ) | (78 | ) |
Protect margin on fixed price sales | | 1 | | 6 | | 3 | | 10 | |
Protect crack spread values | | (18 | ) | (2 | ) | (20 | ) | (5 | ) |
Subtotal, non-trading activities | | (139 | ) | (167 | ) | (112 | ) | (178 | ) |
Trading activities | | 5 | | (7 | ) | 4 | | (2 | ) |
Total net derivative losses | | $ | (134 | ) | $ | (174 | ) | $ | (108 | ) | $ | (180 | ) |
Derivatives used in non-trading activities have an underlying physical commodity transaction. Since the majority of RM&T segment derivative contracts are for the sale of commodities, derivative losses generally occur when market prices increase and typically are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains generally occur when market prices decrease and are typically offset by losses on the underlying physical commodity transactions. The income effect related to the derivatives and the income effect related to the underlying physical transactions may not necessarily be recognized in net income in the same period because we do not attempt to qualify these commodity derivatives for hedge accounting.
Other Commodity Related Risks
We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. For example, natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets, such as the New York Mercantile Exchange (“NYMEX”) contracts for natural gas that are priced at Louisiana’s Henry Hub, while the underlying quantities of natural gas may be produced and sold in the western United States at prices that do not move in strict correlation with NYMEX prices. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased exposure to basis risk. These regional price differences could yield favorable or unfavorable results. Over-the-counter transactions are being used to manage exposure to a portion of basis risk.
We are impacted by liquidity risk, caused by timing delays in liquidating contract positions due to a potential inability to identify a counterparty willing to accept an offsetting position. Due to the large number of active participants, liquidity risk exposure is relatively low for exchange-traded transactions.
Interest Rate Risk
We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. A sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates as of June 30, 2007 is provided in the following table:
(In millions) | | Fair Value | | Incremental Change in
Fair Value | |
| | | | | |
Financial assets (liabilities):(a) | | | | | |
| | | | | |
Receivable from United States Steel | | $ | 509 | | $ | 11 | |
Interest rate swap agreements | | $ | (18) | (b) | $ | 7 | (c) |
Long-term debt, including amounts due within one year | | $ | (4,674) | (b) | $ | (232) | (c) |
(a) Fair values of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
(b) Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
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(c) For interest rate swap agreements, this assumes a 10 percent decrease in the June 30, 2007 effective swap rate. For long-term debt, this assumes a 10 percent decrease in the weighted average yield to maturity of our long-term debt at June 30, 2007.
At June 30, 2007, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to effects of interest rate fluctuations. This sensitivity is illustrated by the $232 million increase in the fair value of long-term debt at June 30, 2007, assuming a hypothetical 10 percent decrease in interest rates. However, our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affect our results of operations and cash flows when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.
We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of the debt portfolio. We have entered into several interest rate swap agreements, designated as fair value hedges, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. On June 1, 2007, $450 million notional amount of our interest rate swap agreements expired. There have been no other changes to the positions subsequent to December 31, 2006.
Foreign Currency Exchange Rate Risk
We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in the foreign currency markets by locking in foreign currency rates. The aggregate effect on foreign currency contracts of a hypothetical 10 percent change to exchange rates at June 30, 2007, would be approximately $6 million. There have been no significant changes to our exposure to foreign exchange rates subsequent to December 31, 2006.
Safe Harbor
These quantitative and qualitative disclosures about market risk include forward-looking statements with respect to management’s opinion about risks associated with the use of derivative instruments. These statements are based on certain assumptions with respect to market prices and industry supply of and demand for crude oil, natural gas, refined products and other feedstocks. If these assumptions prove to be inaccurate, future outcomes with respect to our hedging programs may differ materially from those discussed in the forward-looking statements.
Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. During the quarter ended June 30, 2007, there were no changes in our internal controls over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal controls over financial reporting.
Marathon reviews and modifies its financial and operational controls on an ongoing basis to ensure that those controls are adequate to address changes in its business as it evolves. Marathon believes that its existing financial and operational controls and procedures are adequate.
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