U

Hom.S. Department eland Security o~· ~·· 05; 

United States 

Coast Guard 

Director 

National Pollution Funds Center 

CERTIFIED MAIL NUMBER: 7011 2000 0001 1246 5918 

Dear Mr. White: 

4200 Wilson Blvd Stop 7100 

Arlington VA 20598-7100 

Staff Symbol: Ca 

Toll-Free: 1-800-280-7118 

Fax: 703-872-6113 

Email: ARL-PFNPFCCLAIMSINFO@uscg.mil 

5890 

October 15,2013 

RE: N10036-1974 

The National Pollution Funds Center (NPFC), in accordance with 33 CFR Part 136, denies 

payment on the claim number involving DEEPWATER HORIZON oil spill. 

This determination is based on an analysis of the information submitted by the Claimant and 

information obtained by the NPFC. Please see the attached determination for further details 

regarding the rationale for this decision. 

Disposition of this reconsideration constitutes final agency action. 

. - -

.. - • .::.:. . . CHIEF, CLAIMS ADJUDICATION DIVISION 

U.S. Coast Guard 

By direction 

Enclosures: Claim Summary I Determination 
Claim Number: 

Claimant: 

Type of Claimant: 

Type of Claim: 

Amount Requested: 

FACTS 

CLAIM SUMMARY I DETERMINATION 

Nl0036-1974 

The White Law Firm 

Corporate (US) 

Loss of Profits and Earnings 

$293,980.00 

On or about 20 April 2010, the Mobile Offshore Drilling Unit Deepwater Horizon (Deepwater 

Horizon) exploded and sank in the Gulf of Mexico. As a result of the explosion and sinking, oil 

discharged into the Gulf of Mexico. The Coast Guard designated the source of the discharge and 

identified BP as a responsible party (RP). BP accepted the designation and advertised its OPA 

claims process. On 23 August 2010, the Gulf Coast Claims Facility (GCCF) began accepting and 

adjudicating certain individual and business claims on behalf ofBP. 

On 08 March 2012, the United States District Court, Eastern District of Louisiana issued a 

"Transition Order" (TO) limiting the GCCF's ability to accept, process, or pay claims except as 

provided in that order. The TO created a Transition Process (TP) to facilitate the transition of the 

claims process from the GCCF to a proposed Court Supervised Settlement Program (CSSP). The 

Court granted Preliminary Approval of the proposed settlement agreement on 02 May 20 12, and 

the CSSP began processing claims on 04 June 2012. 

CLAIM AND CLAIMANT 

On 9 August 2013, Mr. Craig White, on behalf of The White Law Firm ("the Claimant") 

submitted a claim to the Oil Spill Liability Trust Fund (OSLTF) seeking $293,980.00 in loss of 

profits or impairment of earning capacity damages allegedly resulting from the Deepwater 

Horizon oil spill. 1 

The Claimant works as an independent practitioner in the oil and gas exploration/production 

industry, developing and administering contracts and subcontracts. Since 2006, the Claimant has 

been continuously under contract with Marathon Oil Co., which included an existing contract 

extended in 2009 to work on the Innsbruk2 Development Project (an offshore platform to be set 

in the Gulf of Mexico). This new assignment was to begin on May 1, 2010, after the completion 

of the Claimant's last project. The contract contained an option to extend through 2011. 

According to the Cliamant his workload level with Marathon was sufficient to preclude any other 

significant work except under extraordinary circumstances. 

About a week before this Innsbruck Project was to begin, the oil spill occurred and, as the project 

was to be in close proximity to the incident location, mobilization to the project site was delayed 

four weeks, then another four weeks, until it was delayed indefinitely. The Claimant states his 

1 See both the cover letter signed by Mr. Craig A. White, dated 29 July 20 13, as we ll as the Optional OSL TF Claim 

Form, dated 29 July 2013. 2 The correct spelling of this project is " lnnsbruck" and as such, this corrected spelling will be used in the remainder 

of the determination . 

2 
income went from $18,875.00/month to $0.00/month. In the aftermath of the spill, the Claimant 

states he was unable to find work for approximately 15 months, as the entire oil and gas industry 

suffered and were not only losing work, but employees and contractors were being laid off/not 

hired. In July 2011, Marathon found new work for the Claimant; however, it was at a lower rate 

and fewer hours. 

The Claimant filed with the Claim Center for Emergency Assistance and Economic Loss on 

6/28/2010 and was denied payment on 23 September 2010 and again on 26 October 2010, 

respectively. Claimant attempted to file with the Offshore Workers assistance, but since he was 

not physically located offshore, he stated he was disqualified from the program. Later, the 

Claimant states he was asked by the GCCF to re-submit his claim only to ultimately be denied 

again in the reconsideration process on 13 June 2013. The claim was denied by the GCCF 

because Harris County, TX was not covered under the economic zone that is part of the class 

action settlement. After next filing with the BP Claims center, the claim was denied on 16 July 

2013. 

The Claimant calculated his alleged losses by taking the $151 ,000.00 he was slotted to make for 

the Marathon Oil contract from May 201 0 through December 2010 plus he states his 2011 

compensation with Marathon was to be $226,500.00 for a total of$377,500.00 less $83,520.00 in 

wages Claimant received in 2011 to arrive at his sum certain of $293,980.00. 

The claim was denied on August 27, 2013 on the grounds that (1) the Claimant failed to provide 

evidence sufficient to prove that his alleged loss was caused by damage to real or personal 

property or natural resources resulting from the discharge or substantial threat of discharge of oil 

resulting from the Deepwater Horizon oil spill and (2) the Claimant failed to demonstrate a loss 

in the amount claimed of$293,980.00. 

REQUEST FOR RECONSIDERATION: 

On October 4, 2013, the Claimant sent a request for reconsideration to the NPFC stating he 

would like the NPFC to reconsider his claim. It is important to note that the majority of the 

Claimant's letter requesting reconsideration addresses the Applicable Law section that was 

incorporated in the NPFC's initial Claim Summary/Determination Form although the NPFC will 

limit this determination decision to the the two reasons the NPFC officially denied the claim. 

The Claimant's arguments pertaining to the two reasons the NPFC denied the claim are as 

follows: 

1- Claimant argues that the NPFC' s remarks in the denial that his alleged loss of profits is the 

result of Marathon's business decision to terminate the contract is not accurate on two 

points. Claimant states the contract was not in fact terminated but that he remained under 

contract with Marathon through the end of2012 and the job order amendment for the 

contract was de-activated. Additionally, Claimant states the project he was originally 

contracted to work on was delayed due to the oil spill and not due to the moratorium; the 

moratorium only caused the extended delay of the Innsbruck Project for which he was 

contracted to work. 

3 
Claimant further states that the delayed Innsbruck Project was funded again in 2012 and 

restarted; however, since he was retained by Marathon Oil for other work beginning July 

2011 , he was unavailable to work on that project. Claimant states that his loss of profits have 

been established via the tax returns for 2009-2012 which he provided in the original claim 

submission; and 

2. Claimant argues that the Deepwater Horizon incident resulted in injury to the natural 

resource, the waters of the Gulf of Mexico, and that the waters became unusable for the 

execution of the Innsbruck Project. Claimant further states that his reduction in income 

was due to the injury to the Gulf of Mexico waters because one cannot secure a permit to 

drill in an area where pollution cleanup is underway, one cannot contract a drill ship 

without a firm and fixed schedule for drilling, and one does not design and build an 

offshore platform without the reasonable probability that both will be available and 

obtainable when needed. 

NPFC Determination on Reconsideration 

Under 33 CFR 136.105(a) and 136.105(e)(6), the claimant bears the burden ofproviding to the 

NPFC all evidence, information, and documentation deemed necessary by the Director, NPFC, to 

support the claim. Under 33 CFR § 136.233, a claimant must establish loss of profits or 

impairment of earning capacity and that the loss was due to the destruction or injury to real or 

personal property or natural resources. The NPFC considered all the documentation submitted 

by the Claimant. The request for reconsideration must be in writing and include the factual or 

legal grounds for the relief requested, providing any additional support for the claim. 3 3 CFR 

136.115(d). 

The NPFC performed a de novo review of the entire claim submission upon reconsideration. 

Upon review of the Claimant's arguments on reconsideration, the NPFC determines that the 

Claimant has again failed to demonstrate a loss of profits in the amount claimed or that the 

alleged loss of profits was due to the injury, destruction, or loss of property or natural resources 

as a result of a discharge or substantial threat of discharge of oil. 

The NPFC acknowledges that it was in error when it stated the contract between the Claimant 

and Marathon was terminated. After a careful review of the evidence in the record, the NPFC 

does not disagree with the Claimant's articulation that the contract as delayed vice terminated. 

Nonetheless, the active contract and the Innsbruck Project was delayed when Marathon delayed 

the Project because of the drilling moratorium. 3 

Marathon reported on March 24,2011 , to its Stakeholders via its Form 10-K, PART I, Item 1. 

Business, subsection North America, paragraph 4 of page 2, it states in relevant part ... "Shortly 

after the moratorium was issued, we temporarily suspended drilling an exploratory well on the 

3 See Marathon Oil Corporation letter to its stockholders, dated 14 March 2011 , which is found at: 

http :1 /www. sec. gov I Arch i ves/edgar/vprr/1 I /9999999997-I 1-004 54 3. 

4 
Innsbruck prospect, located on Mississippi Canyon Block 993." While the Claimant is asserting 

his losses are due to damage to real or personal property or natural resources resulting from the 

discharge or substantial threat of discharge of oil, the NPFC determines, based on a 

preponderance of the evidence, that Marathon delayed the Innsbruck Project due to the 

moratorium issued by the Department of the Interior.4 And as will be more fully discussed 

below, the incident did not cause the moratorium. 

The Decision Memorandum issued by Michael R. Bromwich, Director, Bureau of Ocean Energy 

Management, Regulation and Enforcement, (the moratorium) provides that operations were 

suspended in the Gulf of Mexico and the Pacific regions pursuant to his authority when it is 

determined that activities "pose a threat of serious, irreparable harm or damage" to human or 

animal " life, property, any mineral deposit or the marine, coastal or human environment" or 

"when necessary for the installation of safety or environmental protection equipment." 30 C.P.R. 

§§ 250. 172(b)-(c). 

The moratorium provides that the drilling of wells using subsea blowout preventers (BOPs) or 

surface BOPs on floating facilities was suspended and the approval of pending and future 

applications for permits to drill using the subsea or surface BOPs shall cease through November 

30, 2010 subject to modification if determined that the significant threats to life, property and the 

environment have been sufficiently addressed. In other words the moratorium was put in place 

to: (1) ensure that safety measures are put in place to address the risks of deepwater drilling and 

(2) give industry time to take concerted actions to develop more effective blowout containment 

strategies and capabilities for deepwater operations. 

Claimant argues that his loss of profits was due to the incident because the incident caused injury 

to the Gulf of Mexico (oil pollution) and the waters were unusable for execution of the Innsbruck 

Project because Marathon could not obtain a permit to drill in an area where cleanup actions 

were taking place. Additionally, the moratorium only delayed the Project further. 

Claimant confuses the terms "incident" and "loss of profits damages." While a responsible party 

is liable for removal costs and damages resulting from an incident (33 U.S.C. § 2702(a)), loss of 

profits damages must be due to the injury to, destruction of, or loss of profit or natural resources. 

(33 U.S.C. § 2702(b)(2)(E)). In this claim Claimant argues that the incident caused natural 

resource damage to the Gulf of Mexico and that the damage to the Gulf of Mexico resulted in the 

moratorium; therefore, his loss of profits was due to the damage to the natural resource. His 

argument fails. 

As explained above, the moratorium was put in place for safety reasons and to prevent further 

incidents. While there were resulting impacts of the Government's decision to impose the 

moratorium on drilling new wells, the purpose of the moratorium was to regulate an industry in 

order to improve safety and prevent similar incidents. OPA does not provide that the responsible 

party should be liable under OPA to pay for impacts resulting from governmental regulation nor 

does it provide that the Fund should pay in this instance if the responsible party does not pay. 

5 
Claimant offers no convincing argument that Congress intended the scope of liability and 

compensation to reach so broadly as to encompass new government regulation to prevent future 

accidents. Even if OPA could be read so broadly to encompass such regulatory impacts, 

Claimant has not provided evidence establishing the particular injury, destruction or loss of 

property or natural resources resulted in his loss of profits; Claimant merely argues that the 

heightened regulatory atmosphere imposed by the moratorium slowed the business of offshore 

development and delayed the Innsbruck Project, which is arguably what the Government 

intended. 

Secondly, while Claimant provided his tax returns and an operating report for 2010-2012, he 

provided no information, such as Profit and Loss Statements for 2009 through 2012 that would 

evidence overall saved expensed during the loss period. 5 Thus, the NPFC is unable to determine 

whether or not the amount alleged is the actual net reduction or loss of earnings. 

Based on the foregoing, this claim is again denied because ( 1) the Claimant has failed to 

demonstrate a loss in the amount of $293,980.00 and (2) the Claimant has failed to demonstrate 

that his alleged loss is due to injury or destruction or loss of real or personal property or a natural 

resource. 

This claim is denied upon reconsideration. 

Claim Supervisor: 

Date of Supervisor's review: 10115113 

Supervisor Action: Denial on reconsideration approved 

Supervisor's Comments: 

5 See 36 CFR 136.233 (d) A claimant must clearly indicate any saved overhead and other normal expenses not 

insurred as a result of the incident. 

6 
fW. Marathon ~Oil Corporation 

Dear Fellow Stockholders, 

111111!111 II 

11005344 

As the global economy began its recovery, resulting in stronger demand, prices and margins for our products, Marathon 

was well positioned to benefit as a result of our significant investment program over the past few years. Our net income 

of$2.6 billion in 2010 was 76 percent higher than in 2009. We also realized a more than 10 percent increase in net cash 

provided by operating activities, which allowed us to invest for the future, reduce our debt and increase our quarterly 

dividend. We increased the quarterly dividend 4 percent in 2010, the sixth time over the past eight years. 

The Garyville Major Expansion, the largest single construction project ever undertaken by Marathon, reached full 

operational capacity in first quarter 2010 and performed well throughout the year, adding more than 200,000 barrels 

per day (bpd) of crude oil refining capacity and substantially increasing profitability. 

In the Oil Sands Mining segment, we saw the start of operations at the Athabasca Oil Sands Mining (AOSP) expansion. 

The production from the new Jackpine Mine was offset by a major turnaround at the base Muskeg River Mine completed in 2010. Moving forward, the combined capacity of this operation is expected to deliver significant earnings and 

cash flow for decades to come. We plan for the AOSP Expansion 1 to reach full production by mid-year 2011 . 

Total crude oil and natural gas sales from the Exploration and Production (E&P) segment in 2010 were slightly 

lower than in 2009. Increased operational reliability, particularly in Norway and Equatorial Guinea (EG), largely 

offset the disappointing results of our U.S. Gulf of Mexico Droshky development. 

As part of our ongoing evaluation of our businesses, we continued to optimize our asset base during 2010. We 

completed the sale of a 20 percent interest in Angola Block 32 for $1.3 billion, closed the sale of our St. Paul Park 

refinery and associated assets for a transaction value of $935 million and announced the sale of our interest in the 

Gudrun project in Norway. 

Increased focus on liquids 

Through strategic investments, we increased our opportunity set in unconventional, liquids-rich U.S. resource plays 

by 60 percent during 2010. Including our Canadian in-situ assets, we now hold more than 780,000 net acres across 

North America in liquids-rich resource plays. 

In our impact exploration program, we acquired four blocks in the Iraqi Kurdistan Region. We have a working interest in two exploration wells in this highly prolific region, and both have discovered oil, with further testing ongoing. 

Additionally, we increased our shale position in Poland to 2.3 million net acres across 11 blocks. While our position 

in Poland is targeting natural gas, the higher and more stable prices in Europe make this an attractive area. 

Largely because of low U.S. natural gas prices, we reduced our current drilling for gas, which led to an overall 

reserve replacement of 7 5 percent. However, because of our focus on liquids, we replaced 109 percent of liquid 

hydrocarbon production. · 

Lowering feedstock costs in Refining, Marketing and Transportation 

We continue to focus on value accretive investments such as the $2.2 billion Detroit Heavy Oil Upgrade Project 

(DHOUP). Designed to capitalize on the growing Canadian oil sands production and lower feedstock costs, this 

project is on schedule for completion in the second half of2012. 
Marathon's offshore weD control capabilities 

Following the Deepwater Horizon tragedy, Marathon thoroughly assessed our capacity to manage a catastrophic 

offshore event. We studied published reports of the incident and developed recommendations for maintaining control 

of fluids, secondary and emergency control systems, responsibility and accountability. 

To reinforce our safety culture, we issued the Marathon Health, Environmental and Safety Beliefs, highlighting our 

expectation that workers will communicate openly, honestly and often about safety. We stressed not only their right 

but their obligation to stop work if they have safety concerns. 

We believe that our Company and the industry are targeting the right issues to address offshore safety responsibly 

and effectively so that we can continue meeting our customers' energy needs. 

Creating two highly focused, independent energy companies 

As noted earlier, we have invested heavily over the past few years. We've done so to improve our competitiveness 

and increase value. Given the largest part of this investment is behind us, along with improving global financial 

conditions and the strength of both businesses, the Board of Directors announced in January plans to spin off our 

downstream assets as Marathon Petroleum Corporation (MPC), creating two independent, highly focused energy 

companies. Our priorities are to ensure both companies have strong balance sheets and significant financial flexibility at the expected effective date of June 30, 2011. 

MPC is expected to be the fifth largest U.S. refiner, with geographically and strategically aligned operations across 

the downstream value chain. MPC's operations will include a six-plant refining network with 1,142,000 bpd of crude 

oil refining capacity, an extensive terminal and transportation system and significant marketing operations concentrated in the Midwest, Gulf Coast and Southeast regions of the U.S. 

Marathon Oil Corporation (MRO) will focus on its liquids-rich E&P and Oil Sands Mining segments with upside 

from Integrated Gas. MRO has a solid asset portfolio, including world-class liquids and natural gas processing facilities in EO, major liquid hydrocarbon operations in Norway, oil and natural gas production in key U.S. energy basins, 

an interest in Canada's AOSP, and impact exploration positions in multiple basins. 

Our employees have built what will be two investment grade companies, each with sufficient liquidity and financial 

flexibility to pursue their own strategic objectives. The spin-off and resulting formation of two strong, independent 

companies marks another chapter in our Company's proud 124-year history. As it has been throughout our history, 

our success is largely a result of Marathon's employees. We are especially grateful to our more than 29,000 employees and their ongoing commitment to superior results for investors, business partners, suppliers, communities and 

other stakeholders. 

Respectfully, 

Clarence P. Cazalot Jr. 

Chairman President and Chief Executive Officer 

This annual report marks a shift in the way we communicate financial performance to stakeholders. While the printed report is streamlined, we plan to provide in-depth information on www.marathon.com that we hope will deepen 

your understanding of our operations, values, strengths and future outlook. 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549 

FORM 10-K 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) 

OF THE SECURITIES EXCHANGE ACT OF 1934 

For the Fiscal Year Ended December 31,2010 

Commission file number 1-5153 

Marathon Oil Corporation (Exact name of registrant as specified in 1ts charter) 

Delaware 25-0996816 

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 

5555 San Felipe Road, Houston, TX 77056-2723 

(Address of principal executive offices) 

(713) 629-6600 

(Registrant's telephone nwnber, including area code) 

Securities registered pursuant to Section 12(b) of the Act 

Title of Each Class 

Common Stock, par value $1.00 

N arne of Each Exchange on Which Registered 

New York Stock Exchange 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities 

Act. Yes 0 No D 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 

Act. Yes D No 0 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of 

the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing 

requirements for the past 90 days. Yes 0 No 0 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if 

any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 

(§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was 

required to submit and post such files). Yes 0 No 0 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained 

herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information 

statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 0 

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, 

or a smaller reporting company. See definition of "large accelerated filer," "accelerated filer" and "smaller 

reporting company" in Rule 12b-2 of the Exchange Act. (Check one): 

Large accelerated filer 0 Accelerated filer 0 Non-accelerated filer 0 Smaller reporting company 0 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes 0 No 0 

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2010: $22,006 million. This 

amount is based on the closing price of the registrant's Common Stock on the New York Stock Exchange on that 

date. Shares of Common Stock held by executive officers and directors of the registrant are not included in the 

computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and 

executive officers to be affiliates. 

There were 710,280,842 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 2011. 

Documents Incorporated By Reference: 

Portions of the registrant's proxy statement relating to its 2011 annual meeting of stockholders, to be filed with the 

Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are 

incorporated by reference to the extent set forth in Part lll, Items 10-14 ofthis report. 
MARATHON OIL CORPORATION 

Unless the context otherwise indicates, references to "Marathon," "we," "our," or "us" in this Annual Report on 

Form 10-K are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and 

its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other 

ventures over which Marathon exerts significant influence by virtue of its ownership interest). 

PART I 

PART II 

PART III 

PART IV 

Table of Contents 

Item 1. Business 1 

24 

31 

31 

31 

Item lA. Risk Factors 

Item lB. Unresolved Staff Comments 

Item 2. Properties 

Item 3. Legal Proceedings 

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of 

Equity Securities 34 

Item 6. Selected Financial Data 35 

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 36 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk 58 

Item 8. Financial Statements and Supplementary Data 61 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 122 

Item 9A. Controls and Procedures 122 

Item 9B. Other Information 122 

Item 10. Directors, Executive Officers and Corporate Governance 122 

Item 11. Executive Compensation 122 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder 

Matters 123 

Item 13. Certain Relationships and Related Transactions, and Director Independence 124 

Item 14. Principal Accounting Fees and Services 124 

Item 15. Exhibits, Financial Statement Schedules 124 

SIGNATURES 131 
Disclosures Regarding Forward-Looking Statements 

This Annual Report on Form 10-K, particularly Item 1. Business, Item lA. Risk Factors, Item 3. Legal Proceedings, 

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 7 A 

Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements within the meaning of 

Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements 

typically contain words such as "anticipate," "believe," "estimate," "expect," "forecast," "plan," "predict," "target," "project," 

"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, that could cause future 

outcomes to differ materially from those set forth in the forward-looking statements. 

Forward-looking statements in this Report may include, but are not limited to, levels of revenues, gross margins, 

income from operations, net income or earnings per share; levels of capital, exploration, environmental or maintenance 

expenditures; the success or timing of completion of ongoing or anticipated capital, exploration or maintenance projects; 

volumes of production, sales, throughput or shipments of liquid hydrocarbons, natural gas, synthetic crude oil and refined 

products; levels of worldwide prices of liquid hydrocarbons, natural gas and refined products; levels of reserves of liquid 

hydrocarbons, natural gas and synthetic crude oil; the acquisition or divestiture of assets; the effect of restructuring or 

reorganization of business components; the potential effect of judicial proceedings on our business and financial condition; 

levels of common share repurchases; and the anticipated effects of actions of third parties such as competitors, or federal, 

foreign, state or local regulatory authorities. 

PART I 

Item 1. Business 

Plan to Create Independent Downstream Company 

On January 13, 2011, the Board of Directors of Marathon Oil Corporation ("Marathon") announced that it has 

approved moving forward with plans to spin off our downstream (Refining, Marketing and Transportation) business, 

creating two independent energy companies: Marathon Petroleum Corporation ("MPC") and Marathon Oil Corporation 

("MRO"). To effect the spin-off, · we intend to distribute one common share of MPC for every two common shares of 

Marathon held at a record date to be det ermined. The transaction is expected to be effective June 30, 2011, with 

distribution of MPC shares shortly thereafter. A tax ruling request was submitted to the U.S. Internal Revenue Service 

("IRS") regarding the tax-free nature of the spin-off and we anticipate a response during the second quarter of 2011. 

The above discussion of the plans to create an independent. downstream company includes forward looking 

statements. Factors which could affect the plans include board approval, receipt of a favorable private letter ruling from 

the IRS and a registration statement declared effective by the Securities and Exchange Commission ("SEC"). 

General 

Marathon Oil Corporation was originally organized in 2001 as USX HoldCo, Inc., a wholly-owned subsidiary of the 

former USX Corporation. As a result of a reorganization completed in July 2001, USX HoldCo, Inc. (1) became the parent 

entity of the consolidated enterprise (the former USX Corporation was merged into a subsidiary of USX Hold Co, Inc.) and 

(2) changed its name to USX Corporation. In connection with the transaction described in the next paragraph (the "USX 

Separation"), USX Corporation changed its name to Marathon Oil Corporation. 

Before December 31, 2001, Marathon had two outstanding classes of common stock: USX-Marathon Group common 

stock, which was intended to reflect the performance of our energy business, and USX-U.S. Steel Group common stock 

("Steel Stock"), which was intended to reflect the performance of our steel business. On December 31, 2001, we disposed of 

our steel business through a tax-free distribution of the common stock of our wholly-owned subsidiary United States Steel 

Corporation ("United States Steel") to holders of Steel Stock in exchange for all outstanding shares of Steel Stock on a 

one-for-one basis. 

In connection with the USX Separation, our certificate of incorporation was amended on December 31, 2001, and 

Marathon has had only one class of common stock authorized since that date. 

Segment and Geographic Information 

Our operations consist of four reportable operating segments: 1) Exploration and Production ("E&P") - explores for, 

produces and markets liquid hydrocarbons and natural gas on a worldwide basis; 2) Oil Sands Mining ("OSM") - mines, 

extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and 

1 
market synthetic crude oil; 3) Integrated Gas ("IG") - markets and transports products manufactured from natural gas, 

such as liquefied natural gas ("LNG") and methanol, on a worldwide basis; and 4) Refining, Marketing and Transportation 

("RM&T") - refines, transports and markets crude oil and petroleum products, primarily in the Midwest, Gulf Coast and 

southeastern regions of the United States. For operating segment and geographic financial information, see Note 8 to the 

consolidated financial statements. 

The E&P, OSM and IG segments comprise our upstream operations. The RM&T segment comprises our downstream 

operations. 

Exploration and Production 

In the discussion that follows regarding our exploration and production operations, references to "net" wells, sales or 

investment indicate our ownership interest or share, as the context requires. 

At the end of 2010, we were conducting oil and gas exploration, development or production activities in ten countries: 

the United States, Angola, Canada, Equatorial Guinea, Indonesia, Libya, Norway, Poland, the Iraqi Kurdistan Region, 

and the United Kingdom. 

Our 2010 worldwide net liquid hydrocarbon sales averaged 245 thousand barrels per day ("mbpd"). Our 2010 

worldwide net natural gas sales, including natural gas acquired for injection and subsequent resale, averaged 878 million 

cubic feet per day ("mmcfd"). In total, our 2010 worldwide net sales averaged 391 thousand barrels of oil equivalent per 

day ("mboepd"). For purposes of determining barrels of oil equivalent ("hoe"), natural gas volumes are converted to 

approximate liquid hydrocarl>Qn barrels by dividing the natural gas volumes expressed in thousands of cubic feet ("mcf') 

by six. The liquid hydrocarbon volume is added to the barrel equivalent of natural gas volume to obtain hoe. 

In the United States during 2010, we drilled 77 gross (36 net) exploratory wells of which 73 gross (32 net) wells 

encountered commercial quantities of hydrocarbons. Of these 73 wells, 35 were temporarily suspended or in the process of 

being completed at year end. Internationally, we drilled 10 gross (2 net) exploratory wells of which 7 gross (1 net) wells 

encountered commercial quantities of hydrocarbons. All 7 wells were temporarily suspended or were in the proces1! of 

being completed at December 31, 2010. 

North America 

United States - Our U.S. operations accounted for 29 percent of our 2010 worldwide net liquid hydrocarbon sales 

volumes and 41 percent of our worldwide net natural gas sales volumes. 

Offshore- The Gulf of Mexico continues to be a core area, with over 20 prospects. At year end 2010, we held material 

interests in seven producing fields, four of which are company operated. An eighth field is under development and 

anticipated to come on-line in 2011. 

Gulf of Mexico Drilling Moratorium- On April 22, 2010, the Deepwater Horizon, a rig that was engaged in drilling 

operations in the deepwater Gulf of Mexico, sank after an explosion and fire. The incident resulted in a significant oil spill 

in the Gulf of Mexico. Marathon had no involvement in the incident. 

As a result of the Deepwater Horizon incident, the U.S. Department of the Interior issued a drilling moratorium on 

May 30, 2010, to suspend the <lrilling of deepwater wells, and prohibit drilling any new deepwater wells (defined as 

greater than 500 foot water depth). Shortly after the moratorium was issued, we temporarily suspended drilling an 

exploratory well on the Innsbruck prospect, located on Mississippi Canyon Block 993. Although the drilling moratorium 

was lifted on October 12, 2010, it is not known when plans and permits will be approved for future deepwater drilling 

activity. We sent a Revised Development Operations Coordination Document for the Ozona completion and a Revised 

Exploration Plan for the Innsbruck well to the Bureau of Ocean Energy Management Regulation and Enforcement 

("BOEMRE"). We continue to update our revised Oil Spill Response Plan as new and updated requirements come from the 

BOEMRE. We filed our first deepwater Exploration Plan since the Deepwater Horizon incident to the BOEMRE on 

October 15, 2010. We are continuing to engage the BOEMRE to provide them with all the requested information. The 

BOEMRE has not yet deemed our plan submitted. The effects of new or additional laws or regulations that may be 

adopted in response to this incident are not fully known at this time and may impact future project execution. 

We operate the Ewing Bank 873 platform which is located 130 miles south of New Orleans, Louisiana. The platform 

started operations in 1994 and serves as a production hub for .the Ewing Bank 873 (Lobster), Ewing Bank 917 (Oyster) 

and Ewing Bank 963 (Arnold) fields. The facility also processes third-party production via subsea tie-backs. 

2 
We own a 50 percent interest in the outside-operated Petronius field on Viosca Knoll Blocks 786 and 830. The 

Petroni us platfonn is capable of providing processing and transportation services to nearby third-party fields. 

The Neptune development commenced production of liquid hydrocarbons and natural gas in July 2008. We hold a 30 

percent working interest in this outside-operated development located on Atwater Valley 575, 120 miles off the coast of 

Louisiana. The completed Phase I development included six subsea wells tied back to a stand-alone platfonn. Phase II 

development activities have begun and the first well in this program was successfully drilled and completed in late 2009. 

Our Droshky development in the Gulf of Mexico on Green Canyon Block 244 began production in mid-July of 2010 

and reached peak net production of 45,000 boepd in the third quarter of 2010. Production declines have been steeper than 

anticipated due to reservoir compartmentalization and lack of aquifer support. This subsea project consists of four 

development wells tied back to a third-party platform. Three of the four wells are currently producing. We plan to re-enter 

the fourth well in the first quarter of 2011. We hold a 100 percent operated working interest and an 81 percent net 

revenue interest in Droshky. 

Development of our operated Ozona prospect, located on Garden Banks Block 515, has also continued. We are in the 

process of securing a rig to complete the previously drilled appraisal well and tie back to the· riearby third-party Auger 

platfonn. First production ofliquid hydrocarbon is expected in 2011. We hold a 68 percent working interest in Ozona. 

In 2008, we drilled a successful oil appraisal well on the Stones prospect located on Walker Ridge Block 508. We hold 

a 25 percent interest in the outside-operated Stones prospect. In the third quarter of 2008, we annol:mced deepwater oil 

discovery on the Gunflint prospect located on Mississippi Canyon Block 948. We own a 13 percent interest in this outsideoperated prospect. In the first quarter of 2009, we participated in a deepwater oil discovery on the Shenandoah prospect 

located on Walker Ridge Block 52. We own a 10 percent interest in the outside-operated prospect. 

In December 2009, we began drilling an exploratory well on the Flying Dutchman prospect, located on Green Canyon 

Block 511 in the Gulf of Mexico. We have 63 percent ownership and are the operator of this liquid hydrocarbon prospect. 

The Flying Dutchman reached its targeted total depth in early May 2010. The well encountered hydrocarbon-bearing 

sands that require further technical evaluation. The results of the Flying Dutchman well will continue to be evaluated to 

determine overall commerciality. 

In addition to the prospects listed above, we held interests in 103 blocks in the Gulf of Mexico at the end of 2010, 

including 97 in the deepwater area. Our plans call for exploration drilling on some of these leases in 2011 and 2012, 

presuming a favorable regulatory environment that will allow deep-water drilling to resume. 

Onshore- We hold 391,000 net acres in the Bakken shale oil play in the Williston Basin of North Dakota with a 

working interest of approximately 80 percent. ApproXimately 275 company-operated locations will be drilled over the next 

4 years. We are evaluating other potential horizons above and below the Middle Bakken. We currently have six operated 

drilling rigs running in our Bakken shale program, and will add a rig solely dedicated to completion operations in the first 

quarter of2011. 

In the Anadarko Woodford shale horizon, a liquids-rich play in Oklahoma, we continue to expand our acreage position 

and now hold approximately 88,000 net acres within the play. We have existing production operations in this geographical 

area which will facilitate early drilling, with· initial wells currently in progress. We plan to increase from three to eight 

company operated rigs in 2011. We also have domestic natural gas operations in Oklahoma, East Texas, and North 

Louisiana with combined net gas sales of 103 mmcfd in 2010. 

In December 2010, we entered into an agreement with an operator in the Eagle Ford shale, a liquids-rich play in 

Texas. We initially paid $10 million and will drill and complete four wells to earn approximately 17,000 net acres. We also 

have an option that expires October 31, 2011 to purchase the operator's remaining 58,000 net acres at a total cost of 

approximately $209 million, including the initial payment, carried well interest and lease extensions. In the event that we 

do not exercise .the purchase option, the operator has the option to put the remaining 58,000 acres to us at a total cost, 

includipg .the initial payment, carried well interest and lease extensions, of approximately $92 million. 

We hold leases with natural gas production in the Piceance Basin of Colorado, located in Garfield County in the 

Greater Grand Valley field complex. We acquired approximately 177,000 net acres within the Niobrara play in the DJ 

Basin of northern Colorado and southeast Wyoming. We expect to commence drilling in 2011 and will leverage our 

Bakken operating experience. Net liquid hydrocarbon and natural gas sales from our existing Wyoming fields averaged 24 

mbpd and 106 mmcfd in 2010. We plan to drill approximately 20 company operated wells in 2011 in the Big Horn, Wind 

River and Powder River Basins. 

3 
We hold acreage in two additional emerging shale resource plays in the U.S. In the Appalachian Basin we hold 80,000 

net acres in the Marcellus shale natural gas play in Pennsylvania and West Virginia. In February 2011, we entered into a 

joint venture with a company on a large portion of our Marcellus shale acreage position. Under the agreement terms, the 

company will to eam 50 percent of approximately 60,000 acres under a drilling carry. The company also has an option to 

acquire our remaining acreage while we retain the rights to continue to market the acreage to others. We drilled three 

wells in 2010 and five in 2009. In Louisiana and east Texas, we hold 20,000 net acres in the Haynesville shale natural gas 

play, where we drilled two wells in 2010 and one in 2009. 

We produce natural gas in the Cook Inlet and adjacent Kenai Peninsula of Alaska. We have operated and outsideoperated interests in ten fields and hold a 51 to 100 percent working interest in each. Typically, our natural gas sales from 

Alaska are seasonal in nature, trending down during the second and third quarters of each year and increasing during the 

fourth and first quarters. To manage supplies to meet contractual demand we produce and store natural gas in a partially 

depleted reservoir in the Kenai natural gas field. In 2010, we drilled three operated wells in Alaska and plan to drill one 

to three company-operated wells per year during 2011 and 2012. 

Canada- We hold interests in both operated and outside-operated exploration stage in-situ oil sand leases as a result 

of the acquisition of We stem in 2007. The three potential in-situ developments are N amur, in which we hold a 60 percent 

operated interest, Birchwood, in which we hold a 100 percent operated interest, and Ells River, in which we hold a 20 

percent outside-operated interest. Initial test drilling on the Birchwood prospect confirmed bitumen presence and an 

additional 70 test wells are planned in 2011 to assess reservoir quality. Sanction of the initial phase of the Birchwood 

development is anticipated in 2014, with resulting first production expected in 2016. 

Africa 

Equatorial Guinea - We own a 63 percent operated working interest in the Alba field which is offshore Equatorial 

Guinea. During 2010, Equatorial Guinea net liquid hydrocarbon sales were 15 percent of our worldwide net liquid 

hydrocarbon sales volumes, and net natural gas sales were 46 percent of our worldwide net natural gas sales. 

We also own a 52 percent interest in Alba Plant LLC, an equity method investee that operates an onshore liquefied 

petroleum gas ("LPG'') processing plant. Alba field natural gas is processed by the LPG plant under a long-term contract 

at a fixed price for the British thermal units used in the operations of the LPG plant and for the hydrocarbons extracted 

from the natural gas stream in the form of secondary condensate and LPG. During 2010, a gross 753 mmcfd of natural gas 

was supplied to the LPG production facility and the resulting net liquid hydrocarbon sales volumes in 2010 included 3 

mbpd of secondary condensate and 11 mbpd of LPG produced by Alba Plant LLC. 

As part of our Integrated Gas segment, we own 45 percent of Atlantic Methanol Production Company LLC ("AMPCO") 

and 60 percent of Equatorial Guinea LNG Holdings Limited ("EGHoldings"), both of which are accounted for as equity 

method investments. AMPCO operates a methanol plant and EGHoldings operates an LNG production facility, both 

located on Bioko Island. Dry natural gas from the Alba field, which remains after the condensate and LPG are removed, is 

supplied to both of these facilities under long-term contracts at fixed prices. Because of the location of and limited local 

demand for natural gas in Equatorial Guinea, we consider the prices under the contracts with Alba Plant LLC, AMPCO 

and EGHoldings to be comparable to the price that could be realized from transactions with unrelated parties in this 

market under the same or similar circumstances. Our share of the income ultimately generated by the subsequent export 

of secondary condensate and LPG produced by Alba Plant LLC is reflected in our E&P segment. Our share of the income 

ultimately generated by the subsequent export of methanol produced by AMPCO and LNG produced by EGHoldings is 

reflected in our Integrated Gas segment as discussed below. During 2010, a gross 108 mmcfd of dry natural gas was 

supplied to the methanol plant and a gross 623 mmcfd of dry gas was supplied to the LNG production facility. Any 

remaining dry gas is returned offshore and reinjected into the Alba field for later production. 

We hold a 63 percent operated interest in the Deep Luba discovery on the Alba Block and we are the operator with a 

90 percent interest in the Corona well on Block D. These wells are part of our long-term LNG strategy. We expect these 

discoveries to be developed when the natural gas supply from the nearby Alba field starts to decline. 

Angola- Offshore Angola, we hold 10 percent interests in Block 31 and Block 32, both of which are outside-operated. 

The discoveries on Blocks 31 and 32 represent four potential development hubs. The Plutao, Saturno, Venus and Marte 

discoveries and one successful appraisal well form a planned development area in the northeastern portion of Block 31. In 

· 2008, we received approval to proceed with this first deepwater development project, called the PSVM development. The 

PSVM development will utilize a floating, production, storage and offloading ("FPSO") vesseL A total of 48 production and 

injection wells are planned with development drilling currently underway. First production is anticipated in 2012. Other 

discoveries on Block 31 comprise potential development areas in the southeast and middle portions of the block. A 

development area in the south eastern portion of Block 32 is currently being evaluated with the potential to include 6 

fields for an anticipated first oil production in 2016. 

4 
Libya- We hold a 16 percent interest in the Waha concessions, which encompass almost 13 million acres located in 

the Sirte Basin. Our exploration program in 2010 included the drilling of 10 wells, including 2 carry over wells from 2009: 

seven of these wells were discoveries, two were dry and abandoned, and one was drilling as of yearend. We drilled 28 

development wells in Libya in 2010. Phase II of the Faregh project began commissioning during the third quarter of 2010, 

with production coming on line in November. 

Europe 

Norway - Norway continues to be a core area, which complements our long-standing operations in the U.K. sector of 

the North Sea discussed below. We were approved for our first operatorship on the offshore Norwegian continental shelf in 

2002, where today we operate ten licenses and hold interests in over 240,000 net acres. 

The operated Alvheim complex located on the Norwegian continental shelf commenced production in June 2008. The 

complex consists of a Floating Production, Storage and Offioading ("FPSO") vessel with subsea infrastructure. Improved 

reliability, combined with optimization work, increased the throughput of the FPSO to 142 mbpd, up from the original 

design of 120 mbpd. Produced oil is transported by shuttle tanker and produced natural gas is transported to the existing 

U.K. Scottish Area Gas Evacuation ("SAGE") system using a 14-inch diameter, 24-mile cross border pipeline. First 

production to the complex was from the Alvheim development which is comprised of the Kameleon, East Kameleon and 

Kneler fields, in which we have a 65 percent working interest, and the Boa field, in which we have a 58 percent working 

interest. At the end of 2010, the Alvheim development included 11 producing wells and 2 water disposal wells. A Phase 2 

drilling program commenced in 2010, with 1 well on production since December 2010 and a further two production wells 

to be drilled in 2011. A Phase 2b drilling program consisting of 2 production wells is planned for 2011 and 2012. 

The nearby outside-operated Vilje field, in which we own a 47 percent working interest, began producing through the 

Alvheim complex in August 2008. 

In June 2009, we completed the drilling program for the Volund field as a subsea tieback to the Alvheim complex. The 

Volund development, in which we own a 65 percent operated interest, is located approximately five miles south of the 

Alvheim area and consists of three production wells and one water injection well. First production from Volund was 

announced in September 2009. In the second quarter of 2010, we commenced production at the Volund field which allows 

us to maintain full capacity on the Alvheim FPSO. Net sales from Alvheim, Vilje, and Volund for 2010 averaged 50 mbpd 

of liquid hydrocarbons and 30 mmcfd of natural gas. 

Also offshore Norway, we and our partners announced the Marihone and Viper discoveries, both located within 

tie-back distance of the Alvheim FPSO. The Marihone oil discovery is located in license PL340 about 12 miles south of the 

Volund and Alvheim fields. We hold a 65 percent operated working interest in Marihone. The Viper oil discovery is located 

immediately next to Volund field in PL203, about 12 miles south of the Alvheim FPSO. We are the operator and hold a 65 

percent interest in Viper. Conceptual development studies for both discoveries have begun. First production for both 

discoveries is anticipated in 2014. 

In December 2010 a sales agreement was entered into for all of our interests in production licenses PL 025, PL 048E 

and PL 187. The transaction includes our outside-operated 20 percent interest in PL 025 (Gudrun field development) and 

PL 187 (Brynhild discovery), and 12.5 percent interest in PL .048E (Eirin discovery). 

United Kingdom- Our largest asset in the U.K. sector of the North Sea is the Brae area complex where we are the 

operator and have a 42 percent working interest in the South, Central, North and West Brae fields and a 38 percent 

working interest in the East Brae field. The Brae A platform and facilities host the underlying South Brae field and the 

adjacent Central and West Brae fields. A two well development program commenced in 2010 for West Brae with one well 

on production in January 2011, and the second expected to produce by the end of March 2011. The North Brae field, which 

is produced via the Brae B platform, and the East Brae field, which is produced via the East. Brae platform, are natural 

gas condensate fields. The East Brae platform hosts the nearby Braemar field in which we have a 28 percent working 

interest. 

The strategic location of the Brae platforms along with pipeline and onshore infrastructure has generated third-party 

processing and transportation business since 1986. Currently, the operators of 30 third-party fields have contracted to use 

the Brae system. Most recently, in 2010, we agreed to commence construction and installation of a new module to 

accommodate the tie back of the third-party operated Devenick field. In addition to generating processing and pipeline 

tariff revenue, this third-party business also has a favorable impact on Brae area operations by optimizing infrastructure 

usage and extending the economic life of the complex. 

The Brae group owns a 50 percent interest in the outside-operated SAGE system. The SAGE pipeline transports 

natural gas from the Brae area, and the third-party Beryl area, and has a total wet natural gas capacity of 1.1 billion 

"5 
cubic feet ("bcf') per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE 

pipeline as well as approximately 1 bcfper day ofthird-party natural gas. 

In the U.K. Atlantic Margin west of the Shetland Islands, we own an average 30 percent working interest in the 

outside-operated Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, 4 7 

percent working interest in East Foinaven and 20 percent working interest in the T35 and T25 fields. The FPSO is being 

upgraded which is expected to extend the life of this asset through 2021. 

Poland- In 2010, we added 10 licenses with shale gas potential in Poland, increasing our total acreage position to 

approximately 2.3 million net acres in 11 licenses. We have a 100 percent interest and operate all 11 blocks. In 2011 we 

plan to acquire 2D seismic over all concessions by the end of the third quarter and plan to initiate drilling in the fourth 

quarter. We have recently been successful in farming-out a portion of our interest in this play. Under the agreement, our 

partner will earn a 40 percent working interest in 10 licenses, as well as pay a promote on certain future seismic and well 

costs. This transaction is subject to the approval of the Polish Ministry of the Environment. We will remain operator of the 

10 licenses included in the agreement. 

Other International 

Indonesia - We are the operator and hold a 70 percent interest in the Pasangkayu Block located both onshore & 

offshore Sulawesi in the Makassar Strait, Indonesia. The Pasangkayu Block covers an area of approximately 872,000 

acres and is located directly east of the Kutei Basin production region. The production sharing contract with the 

Indonesian government was signed in 2006 and we completed 3D seismic acquisition in May 2008. 

In November 2010, the Bravo-1 well in the northeastern portion of the Pasangkayu block was drilled in a water depth 

of approximately 3,200 feet and reached a total depth of9,000 feet. No hydrocarbon accumulations were present. 

The Romeo prospect, located on the north-central portion of the Pasangkayu block in a water depth of 6,200 feet, is 

being drilled and is expected to be completed during the first half of 2011. 

In 2009, we were awarded a 49 percent interest and operatorship in the Kumawa Block, an Indonesia offshore 

exploration block, located offshore West Papua. An increase in ownership to 55 percent received Indonesian government 

approval in late 2010. The Kumawa Block encompasses 1.24 million acres. A seismic survey was acquired in 2010 and we 

expect to drill one exploration well in 2012. 

In October 2008, we were granted a 49 percent interest and operatorship in the Bone Bay Block offshore Sulawesi. An 

increase in ownership to 55 percent received Indonesian government approval in late 2010. The Bone Bay Block covers an 

area of 1.23 million acres and is 200 miles southeast of our Pasangkayu Block. A 2D seismic survey was acquired in 2009 

and we expect to drill one exploration well in early 2012. 

We continue to pursue joint study agreements in Indonesia, which provide a right of first refusal in future bid rounds. 

We completed one joint study agreement in 2010 and continue to evaluate regional potential for other opportunities. 

Iraqi Kurdistan Region - In October 2010, we acquired a position in four exploration blocks in the Kurdistan Region 

of Iraq. We have signed production sharing agreements for operatorship and an 80 percent ownership in two open blocks 

northeast of Erbil; Harir and Safim. The Kurdistan Regional Government ("KRG") will hold a 20 percent carried interest. 

We were assigned working interests in two additional blocks located north-northwest ofErbil; Atrush, in which we have a 

16 percent ownership (KRG holds a 4 percent carried interest), and Sarsang, in which we have a 20 ownership (KRG holds 

a 4 percent carried interest). These contracts provide us with access to approximately 368,000 net acres. We have 

committed to a seismic program and to drilling one well on each of the two open blocks during the initial three-year 

exploration period. The Atrush and Sarsang blocks each have one well currently drilling. 

Divestitures 

Angola- In February 2010, we closed the sale of an undivided 20 percent interest in the outside-operated production 

sharing contract and joint operating agreement on Block 32 offshore Angola effective January 1, 2009. We retained a 10 

percent interest in Block 32. 

The above discussion of the E&P segment includes forward-looking statements with respect to anticipated future 

exploratory ahd development drilling, the timing of production from the Ozona development in the Gulf of Mexico, the 

PSVM development on Block 31 offshore Angola and Block 32 and other possible developments. Some factors which could 

possible affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount 

of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards 

such as weather conditions, natural disasters, acts of war or terrorist acts and the governmental or military response, and 

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