• Oil Sands Mining ("OSM") which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.

• Integrated Gas ("IG") which produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG") and methanol, in Equatorial Guinea.

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 2011 Annual Report on Form 10-K.
Key Operating and Financial Activities
In the third quarter of 2012, notable items were:
• Net liquid hydrocarbon and natural gas sales volumes of 452 thousand barrels of oil equivalent per day ("mboed"), of which 65 percent was liquid hydrocarbons

• Net international liquid hydrocarbon sales volumes, for which average realizations have exceeded West Texas Intermediate ("WTI") crude oil, were 62 percent of total liquid hydrocarbon sales

• Eagle Ford shale average net sales volumes of 40 mboed, an increase of 90 percent from the second quarter of 2012

• Production from Libya increased over the second quarter of 2012, with average net sales of 53 mboed

• Bakken shale average net sales volumes of 30 mboed, a 87 percent increase over the same quarter of last year

• Closed the acquisition of Paloma Partners II, LLC

• Assumed operatorship of the Vilje field offshore Norway

Some significant fourth quarter activities through November 7, 2012 include:
• Closed acquisition of an additional 4,300 net acres in the core of the Eagle Ford shale

• Signed agreement for a 20 percent non-operated interest in the South Omo concession onshore Ethiopia

• Reentered Gabon by acquiring an interest in an exploration license

• Acquired interests in two onshore exploration blocks in Kenya

• Farmed out 35 percent working interests in the Harir and Safen blocks in the Kurdistan Region of Iraq

• Issued $2 billion of senior notes

Overview and Outlook
Exploration and Production
Production
Net liquid hydrocarbon and natural gas sales averaged 452 mboed during the third quarter and 414 mboed in the first nine months of 2012 compared to 349 mboed and 362 mboed in the same periods of 2011. Net liquid hydrocarbon sales volumes increased in the U.S. for both the third quarter and first nine months of 2012, reflecting the impact of production from the Eagle Ford shale assets acquired in the fourth quarter of 2011 and our ongoing development programs in the Eagle Ford, Bakken and Anadarko Woodford shale resource plays. The resumption of sales from Libya in the first quarter of 2012 after production had ceased there in February of 2011 was the most significant increase in international sales volumes. In addition, net liquid hydrocarbon sales volumes from the U.K. were lower in the 2012 periods than in the same periods of 2011 due to turnarounds in the third quarter and the timing of liftings. In 2012, we continued to ramp up operations in the core of the Eagle Ford shale play in Texas. Average net sales volumes from the Eagle Ford shale were 40 mboed and 25 mboed in the third quarter and first nine months of 2012. As announced in August, we have reduced our rig count to 18 operated rigs while maintaining four dedicated hydraulic fracturing crews and two more on a spot basis. During the third quarter of 2012, we drilled 78 gross wells and brought 73 gross wells to sales for a total of 180 gross wells drilled in the first nine months of 2012. Our average time to drill a well in the Eagle Ford shale has decreased to approximately 24 days; therefore, we now expect to drill 250 to 260 gross Eagle Ford wells during 2012, an increase of approximately 20 wells from previous estimates. In addition to the improvements in the speed and efficiency in drilling and completions, we continue to optimize well spacing which could significantly increase drillable locations and recoverable resources. We have been performing spacing pilot programs in the Eagle Ford shale which will complete early in 2013 so that we will have applicable technical results by mid-year. To complement drilling and completion activity in the Eagle Ford shale, we continue to build infrastructure to support production growth across the operating area. We are now able to transport approximately 60 percent of our Eagle Ford production by pipeline.
Average net sales volumes from the Bakken shale were 30 mboed and 27 mboed in the third quarter and first nine months of 2012 compared to 17 mboed and 15 mboed in the same periods of 2011. Our Bakken shale liquid hydrocarbon volumes averaged approximately 90 percent crude oil, 5 percent natural gas liquids and 5 percent natural gas in the first nine months of 2012. During the third quarter and first nine months of 2012, we drilled 25 gross and 72 gross wells with seven rigs, with a total of 30 gross and 77 gross wells brought to sales in the third quarter and the first nine months of 2012. By the end of October 2012, we had reduced our operated rig count in the Bakken shale to five. We continue to focus on downspacing and development in the Three Forks area.
In the Anadarko Woodford shale, net sales volumes averaged 10 mboed and 7 mboed during the third quarter and first nine months of 2012 compared to 2 mboed and 2 mboed in the same periods of 2011. During the third quarter of 2012, eight gross wells were brought to sales, with 14 gross wells brought to sales in the first nine months of 2012. As announced in August, in response to the continued decline in natural gas liquids prices and low natural gas prices, we have reduced our rig count in the Anadarko Woodford play from six to two. Other areas of potential growth exist in Oklahoma and we are currently evaluating opportunities on legacy assets where the acreage is held by production. Future activity in these Oklahoma resource basins will be dependent upon the recovery of natural gas and natural gas liquids prices.
In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed and has increased during 2012 so that during the third quarter and first nine months of 2012, net sales volumes averaged 53 mboed and 51 mboed. We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains.
In June 2012, we submitted a plan for the development and operation of the Boyla field (PL 340) in the North Sea to the Norwegian Ministry of Petroleum and Energy, which was approved in October 2012. The Boyla field is located approximately 17 miles south of our operated Alvheim field. We hold a 65 percent working interest in the field. First production from Boyla is expected in the fourth quarter of 2014.
In the second quarter of 2012, we completed a four-day turnaround in Norway that was originally scheduled for 14 days in the third quarter. During the third quarter of 2012, we became operator of the Vilje field offshore Norway in which we own a 47 percent interest.
A 28-day turnaround began at our production operations in Equatorial Guinea on March 23, 2012. It was completed in April 2012, seven days ahead of schedule and below budget.
Our Ozona development in the Gulf of Mexico began production in December 2011. During the first quarter of 2012, production rates declined significantly and have remained below initial expectations. Accordingly, our reserve engineers performed

an evaluation of our future production as well as our reserves which concluded in early April 2012. This resulted in a 2 million barrels of oil equivalent reduction in proved reserves and a $261 million impairment charge in the first quarter of 2012.
Exploration
The appraisal well on the Shenandoah prospect located on Walker Ridge Block 51 in the Gulf of Mexico, in which we have a 10 percent outside-operated working interest, is currently drilling. In the third quarter of 2012, we resumed drilling the exploration well on the Gulf of Mexico Innsbruck prospect on Mississippi Canyon Block 993 in which we hold a 45 percent operated working interest. Through September 30, 2012, our net costs related to the well were $71 million. The well has drilled through multiple horizons with no commercial hydrocarbons found as of November 6, 2012. We anticipate reaching total depth within the next few days at a total net cost, including asset retirement obligations and leasehold costs, of approximately $100 million. In the second quarter of 2012, a Gunflint prospect appraisal well confirmed expected reservoir properties and continuity, establishing the commercial viability of the field. The Gunflint discovery is located on Mississippi Canyon Block 948 and we have a 15 percent outside-operated working interest in the prospect. During the second quarter of 2012, the well costs and related unproved property costs related to the Kilchurn well were charged to exploration expenses.
We continue exploratory drilling in Poland where we hold a 51 percent working interest in 10 operated concessions and a 100 percent working interest in one concession. We have drilled 4 exploratory wells and are currently drilling a fifth well. We have collected extensive data, including well logs and core samples, which are being evaluated. We plan to begin a sixth well by year end 2012 which should reach total depth in 2013.
In the Kurdistan Region of Iraq, we began drilling our first operated exploration well on the Harir block in July 2012 and plan to drill an operated exploration well on the Safen block in the first quarter of 2013. After the farm out discussed below, we have 45 percent working interests in both the Harir and Safen blocks. On the non-operated Atrush block, we participated in an appraisal well during the third quarter of 2012. Additionally, we participated in a non-operated well that commenced drilling on the Sarsang block in September 2012. We hold a 20 percent working interest in the Atrush block and a 25 percent working interest in the Sarsang block.
During the first quarter of 2012, on the Birchwood oil sands lease located in Alberta, Canada, we conducted a seismic survey and drilled six water wells. We also submitted a regulatory application for a proposed 12 thousand barrel per day ("mbbld") steam assisted gravity drainage ("SAGD") project at Birchwood. Pending regulatory approval, project sanction is expected in 2014, with first oil projected in 2017. We have a 100 percent working interest in Birchwood.
Acquisitions and Dispositions
We continually evaluate ways to optimize our portfolio for profitable growth through acquisitions and dispositions, with a previously stated goal of divesting between $1.5 billion and $3 billion over the period of 2011 through 2013. To date, we have entered into agreements for approximately $1.1 billion in divestitures, of which more than $700 million have been completed. Included in the $1.1 billion noted above is the pending sale of our Alaska assets which is discussed below.
On November 1, 2012, we closed the acquisition of an additional 4,300 net acres in the core of the Eagle Ford shale at a transaction cost of approximately $232 million before closing adjustments. This acquisition increased our average working interest by 5 to 7 percent in four core areas of mutual interest, included wells producing 3 net mboed at closing, and added 40 net drilling locations to our inventory. The closing of this transaction combined with the acquisition of Paloma Partners II, LLC ("Paloma acquisition"), brings our acquisitions thus far in 2012 in the core of the play to almost 25,000 additional net acres at an approximate cost of $1 billion. The Paloma acquisition closed in August 2012 as discussed below. We now have approximately 230,000 net acres in the core of the Eagle Ford shale. The unproved property costs related to an additional 100,000 non-core net acres were impaired in the third quarter of 2012 as discussed below in Results of Operations. In October 2012, we entered into an agreement to acquire a 20 percent non-operated working interest in the South Omo concession onshore Ethiopia with an effective date of August 17, 2012. An exploration well is anticipated to commence drilling in South Omo during the fourth quarter of 2012. Cash consideration for this transaction will be $40 million, before closing adjustments, with an additional payment of $10 million due upon declaration of a commercial discovery. We expect to close the transaction, subject to necessary Ethiopian government approvals, before the end of 2012.
We acquired approximately 20,000 net acres in the core of the Eagle Ford shale during the first nine months of 2012. The largest transaction was the acquisition of Paloma Partners II, LLC, which closed August 1, 2012 for cash consideration of $768 million. In addition to the over 17,100 net acres acquired, at closing 17 gross operated and 9 gross non-operated wells were producing an average of 9 net mboed, of which 70 percent was liquid hydrocarbons. Smaller transactions closed during the second quarter of 2012. See Note 6 to the consolidated financial statements for further details of the Paloma acquisition.
In the third quarter of 2012, we sold approximately 5,800 net undeveloped acres located outside the core of the Eagle Ford shale for proceeds of $9 million, recording a loss of $18 million.

In July 2012, we entered into an agreement to acquire outside-operated positions in two onshore exploration blocks in northwest Kenya. Upon closing the $35 million transaction in October 2012, we now hold a 50 percent working interest in Block 9, where an exploration well is currently planned in mid-2013, and a 15 percent working interest in Block 12A.
Also in July 2012, we agreed to farm out interests in the Harir and Safen blocks in the Kurdistan Region of Iraq. The transaction closed in October 2012 and we received cash proceeds of $140 million, so that we now have a 45 percent working interest and carry the KRG for an additional 11 percent in each of the two blocks.
In June 2012, we entered an agreement to acquire a 21 percent outside-operated working interest in the Diaba License G4-223 and its related permit onshore Gabon. The transaction closed in October 2012. The start of exploration drilling is expected in the first quarter of 2013.
During June 2012, we signed a new production sharing contract with the government of Equatorial Guinea for the exploration of Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. We have an 80 percent operated working interest in this block. The contract was ratified by the government in the third quarter of 2012. We also acquired an additional interest in Block D, bringing our working interest to 80 percent.
In May 2012, we executed agreements to relinquish our E&P segment's operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia. As a result, we accrued and reported a $36 million loss on disposal of assets in the second quarter of 2012. Government ratification of the agreements was received during the third quarter of 2012, which released us from our obligations and further commitments related to these licenses, and we paid the amount accrued.
In April 2012, we entered agreements to sell our Alaska assets. One transaction closed in the second quarter of 2012 with proceeds and a net gain of $7 million. The remaining transaction, with a value of $375 million before closing adjustments, is currently under review by the Federal Trade Commission and the Alaska Attorney General's office, which could impact the closing of this transaction.
In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This includes our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded in the first quarter of 2012.
The above discussions include forward-looking statements with respect to the expected production in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, anticipated drilling rig and drilling activity, the sale of our Alaska assets, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, the expected closing of an agreement in Ethiopia, anticipated exploration activity in Ethiopia, Gabon, Poland and the Kurdistan Region of Iraq and the timing of the commencement of construction and first oil on the SAGD project. The projected asset dispositions through 2013 are based on current expectations, estimates, and projections and are not guarantees of future performance. Factors that could potentially affect the expected production in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, exploratory activity in Ethiopia, Gabon, Poland and the Kurdistan Region of Iraq, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play and anticipated drilling rig and drilling activity include pricing, supply and demand for liquid hydrocarbons and natural gas, 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 thereto, and other geological, operating and economic considerations. The completion of the sale of our Alaska assets is subject to necessary government and regulatory approvals and customary closing conditions. The agreement in Ethiopia is subject to government approvals. The timing of commencement of construction and first oil on the SAGD project can be affected by delays in obtaining and conditions imposed by necessary government and third-party approvals, board approval, transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, and the other risks associated with construction projects. 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 the our control and difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Oil Sands Mining
Our OSM operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project ("AOSP"). As announced in October 2012, we have engaged in discussions with respect to a potential sale of a portion of our 20 percent interest. Given the uncertainty of such a transaction, potential proceeds have not been included in our previously stated goal of divesting between $1.5 billion and $3 billion between 2011 and 2013.
Our net synthetic crude oil sales were 53 mbbld and 47 mbbld in the third quarter and first nine months of 2012 compared to 50 mbbld and 43 mbbld in the same periods of 2011. The upgrader expansion was completed and commenced operations in the third quarter of 2011 and subsequent periods' sales volumes have increased as a result. With production capacity at the AOSP

now at 255,000 gross barrels per day, the focus will be on improving operating efficiencies and adding capacity through debottlenecking.
The Energy and Resources Conservation Board, Alberta's primary energy regulator, conditionally approved the AOSP's Quest Carbon Capture and Storage ("Quest CCS") project in July 2012. The AOSP partners approved Quest CCS in the third quarter of 2012.
The above discussion contains forward-looking statements with regard to discussions with respect to a potential sale of a portion of our 20 percent interest in the AOSP. The potential sale of a portion of our interest in the AOSP is subject to successful negotiations and execution of definitive agreements. 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 difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Integrated Gas
LNG and methanol sales from Equatorial Guinea are conducted through equity method investees that purchase dry gas from our E&P assets in Equatorial Guinea. Our share of LNG sales totaled 7,065 metric tonnes per day ("mtd") for the third quarter and 6,277 mtd for the first nine months of 2012 compared to 6,935 mtd and 7,121 mtd in the same periods of 2011. For the first nine months, LNG sales volumes are below the prior year due to a turnaround in the second quarter of 2012 at the facility in Equatorial Guinea, but primarily because the first nine months of 2011 also included LNG sales from Alaska, which ceased when our interest in that production facility was sold in the third quarter of 2011. Market Conditions
Exploration and Production
Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows. Prices have been volatile in recent years. The following table lists benchmark crude oil and natural gas price averages in the third quarter and first nine months of 2012 compared to the same periods in 2011.

                                         Three Months Ended September 30,       Nine Months Ended September 30,
Benchmark                                    2012                2011              2012                2011
WTI crude oil (Dollars per barrel)               $92.20              $89.54            $96.16              $95.47
Brent (Europe) crude oil (Dollars per
barrel)                                         $109.61             $113.46           $112.17             $111.93
Henry Hub natural gas (Dollars per
million
British thermal units ("mmbtu"))(a)               $2.81               $4.19             $2.59               $4.16

(a) Settlement date average.

Average WTI crude oil benchmark prices increased 3 percent in the third quarter of 2012 compared to the same quarter of 2011. Our international crude oil production is relatively sweet and a majority is sold in relation to the Brent crude oil benchmark, which was 3 percent lower in the third quarter of 2012 than the same quarter of 2011. Both crude benchmarks were relatively flat on average when comparing the nine-month periods of 2012 and 2011.
Our domestic crude oil production was about 35 percent sour in the third quarter and 42 percent sour in the first nine months of 2012 compared to 64 percent and 62 percent in the same periods of 2011. Reduced production from the Gulf of Mexico and increased onshore production from the Bakken and Eagle Ford shale plays contributed to the lower sour crude percentage in 2012. Sour crude oil contains more sulfur than light sweet WTI. Sour crude oil also tends to be heavier than and sells at a discount to light sweet crude oil because of its higher refining costs and lower refined product values.
A significant portion of our natural gas production in the lower 48 states of the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas. Average Henry Hub settlement prices for natural gas were lower for the third quarter and first nine months of 2012 compared to the same periods of the prior year. A decline in average settlement date Henry Hub natural gas prices began in September 2011 and continued into 2012. Although prices have stabilized recently, they have not increased appreciably.
Our other major natural gas-producing regions are Europe and Equatorial Guinea. Natural gas prices in Europe have been higher than in the U.S. in recent periods. In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. The natural gas sales from Equatorial Guinea are at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.

Oil Sands Mining
OSM segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil and vacuum gas oil we produce. Roughly two-thirds of our normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil market, primarily Western Canadian Select ("WCS"). In 2012, the WCS discount from WTI has increased, bringing down our average price realizations. Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader.
The operating cost structure of the oil sands mining operations is predominantly fixed, and therefore many of the costs incurred in times of full operation continue during production downtime, making per unit costs sensitive to production rate. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude prices respectively.
The table below shows benchmark prices that impacted both our revenues and variable costs for the third quarter and first nine months of 2012 and 2011:

                                         Three Months Ended September 30,       Nine Months Ended September 30,
Benchmark                                    2012                2011              2012                2011
WTI crude oil (Dollars per barrel)               $92.20              $89.54            $96.16              $95.47
Western Canadian Select (Dollars per
barrel)(a)                                       $70.49              $72.14            $74.21              $76.10
AECO natural gas sales index (Dollars
per mmbtu)(b)                                     $2.27               $3.70             $2.03               $3.86

(a) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

(b) Monthly average AECO day ahead index.

Integrated Gas
We have a 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract principally based upon Henry Hub natural gas prices.
We own a 45 percent interest in a methanol plant located in Equatorial Guinea. Methanol demand has a direct impact on the plant's earnings. Because . . .