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COP > SEC Filings for COP > Form 10-Q on 5-Nov-2013All Recent SEC Filings

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Form 10-Q for CONOCOPHILLIPS


5-Nov-2013

Quarterly Report


Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management's Discussion and Analysis is the Company's analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the Company's plans, strategies, objectives, expectations and intentions that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. The words "anticipate," "estimate," "believe," "budget," "continue," "could," "intend," "may," "plan," "potential," "predict," "seek," "should," "will," "would," "expect," "objective," "projection," "forecast," "goal," "guidance," "outlook," "effort," "target" and similar expressions identify forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 52.

Due to the separation of our downstream businesses in 2012, the sale of our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) on October 31, 2013, and the intention to sell our Nigerian and Algerian businesses, which are all reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips' earnings. The terms "earnings" and "loss" as used in Management's Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world's largest independent exploration and production (E&P) company, based on production and proved reserves. Headquartered in Houston, Texas, we have operations and activities in 29 countries. At September 30, 2013, we had approximately 18,000 employees worldwide and total assets of $120 billion.

Discontinued Operations

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our "Downstream business"), were transferred to Phillips 66. As part of our asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in Kashagan and our Nigerian and Algerian businesses. Results of operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 3-Discontinued Operations, in the Notes to Consolidated Financial Statements.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our asset base reflects our legacy as a major company with a strategic focus on higher-margin developments. Our diverse portfolio primarily includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in Alaska, Europe, Asia and Australia; several major international developments; and a growing conventional and unconventional inventory of global exploration prospects. Our value proposition to our shareholders is to deliver production and cash margin growth, competitive returns on capital, and a compelling dividend, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. We expect to achieve this value proposition through optimizing our portfolio, investing in high-margin developments, applying technical capability and maintaining financial flexibility.


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In the third quarter of 2013, we achieved production of 1,514 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 44 MBOED. Consistent with our commitment to offer our shareholders a compelling dividend, in July 2013, our Board of Directors increased our quarterly dividend by 4.5 percent to $0.69 per share. Through September 2013, we generated $11.9 billion in cash from continuing operations, paid dividends on our common stock of $2.5 billion, funded an $11.9 billion capital program and continued to progress the asset disposition program.

During the first nine months of 2013, we received proceeds from dispositions of $3.2 billion, which mainly resulted from:

The sale of our Clyden undeveloped oil sands leasehold, located in Canada.

The disposition of our 39 percent equity investment in Phoenix Park Gas Processors Limited, located in Trinidad and Tobago.

The sale of certain properties in the Cedar Creek Anticline, located in North Dakota and Montana.

The disposition of a portion of our working interests in the Poseidon discovery in the Browse Basin and the Goldwyer Shale in the Canning Basin.

The disposition of certain properties located in southwest Louisiana.

The sale of our 10 percent interest in the Interconnector Pipeline, located in Europe.

On October 31, 2013, we received additional proceeds of $5.4 billion from the disposition of our 8.4 percent interest in Kashagan. As part of our 2012-2013 disposition program, we have generated $10.7 billion in proceeds through October 31, 2013, which has exceeded our goal of raising $8-$10 billion in proceeds from disposition of non-strategic assets during 2012 and 2013. The previously announced sales of Nigeria, excluding Brass LNG, and Algeria are targeted to close by the end of 2013 and generate approximately $3.4 billion in proceeds, plus customary adjustments. The sale of Brass LNG is targeted to close in the first quarter of 2014 and would generate approximately $105 million in proceeds.

Because we participate in a capital-intensive industry, we make significant investments to acquire acreage, explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, and construct pipelines and liquefied natural gas (LNG) facilities. We expect our full-year 2013 capital program will be approximately $16 billion for continuing operations and $0.6 billion for discontinued operations. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on higher-margin liquids plays and limited investment in North American conventional natural gas. As investments bring more liquids production online, we expect a corresponding shift in our production
mix. However, there are often long lead times from the time we make an investment to the time the investment is operational and begins generating financial returns. In the near-term, we plan to fund a portion of our capital program with the proceeds from asset dispositions. Over the next five years, our investment in high-margin developments should position us to deliver 3 to 5 percent annual production volume and margin growth, enabling us to fund our capital program organically.

Business Environment

The business environment for the energy industry has historically experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the global financial crisis and recession which began in 2008, geopolitical events or fears thereof, environmental laws, tax regulations, governmental policies, and weather-related disruptions. More recently, North America's energy landscape has been transformed from resource scarcity to an abundance of supply, as a result of advances in technology responsible for the rapid growth of shale production, successful development in the deepwater Gulf of Mexico and rising production from the Canadian oil sands. These dynamics generally influence world energy markets and commodity prices. The most significant factor impacting our profitability and related reinvestment of operating cash flows into our business is commodity prices, which can be very volatile; therefore, our strategy is to maintain a strong balance sheet with a diverse portfolio of assets, which we believe will provide the financial flexibility to withstand challenging business cycles.


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The following table depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:

                                                                        Dollars Per Unit

                                                         Three Months Ended          Nine Months Ended
                                                            September 30                September 30

                                                            2013         2012          2013         2012

Market Indicators
WTI (per barrel)                                       $  105.80        92.11         98.07        96.18
Dated Brent (per barrel)                                  110.32       109.61        108.44       112.09
U.S. Henry Hub first of month (per million British
thermal units)                                              3.58         2.80          3.67         2.58

Industry crude prices for WTI increased 15 percent in the third quarter of 2013, compared with the same period in 2012, as new infrastructure allowed increased movement of physical barrels away from Cushing, Oklahoma, and toward the U.S. Gulf Coast refining centers. Brent prices remained relatively flat in the third quarter of 2013, as growth in global oil demand was met by rising production, primarily stemming from U.S. oil production.

Henry Hub natural gas prices increased 28 percent in the third quarter of 2013, compared with the same period in 2012, as storage inventories were much lower in 2013.

The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 17 percent in the first nine months of 2013, compared with the same period of 2012. Bitumen prices continued to strengthen during the third quarter of 2013, as a result of fewer infrastructure constraints downstream of the Hardisty Terminal, which have more than offset the increase in supplies. Our realized bitumen price was $76.06 per barrel in the third quarter of 2013, an increase of 34 percent compared with the third quarter of 2012.

Key Operating and Financial Highlights

Significant highlights during the third quarter of 2013 included the following:

Achieved third-quarter guidance with production of 1,514 MBOED, including continuing operations of 1,470 MBOED, which reflects two months of disruptions in Libya, and discontinued operations of 44 MBOED.

Successfully completed major turnarounds and tie-in activities as planned.

Eagle Ford, Bakken and Permian production increased 40 percent compared with third-quarter 2012.

Started up major projects at Christina Lake Phase E in July and Ekofisk South in October, with final preparations underway for full-field startup at Gumusut, Jasmine and Siakap North-Petai.

High level of exploration activity continues with drilling in the Gulf of Mexico, Australia's Browse Basin, and unconventional plays in Canada and the Lower 48.

Completed sale of Clyden and our interest in Phoenix Park.

Outlook

Fourth-quarter production from continuing operations is expected to be 1,485 to 1,525 MBOED, which reflects a 50 MBOED reduction for the assumed closure of the Es Sider crude oil export terminal in Libya for the entire quarter. Full-year 2013 production from continuing operations is expected to be 1,505 to 1,515 MBOED. Full-year production from discontinued operations is expected to be 35 to 45 MBOED.


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Freeport LNG

In July 2013, we reached agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur by the end of the first quarter of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a net cash outflow of approximately $80 million for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in operating costs over the next 19 years. For additional information, see Note 4-Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2013, is based on a comparison with the corresponding periods of 2012.

A summary of income (loss) from continuing operations by business segment follows:

                                                       Millions of Dollars
                                          Three Months Ended          Nine Months Ended
                                             September 30                September 30
                                            2013          2012          2013         2012


   Alaska                              $     494           535         1,719        1,706
   Lower 48 and Latin America                498           182           878          556
   Canada                                    642           (31)          780         (674)
   Europe                                    284           132           976        1,190
   Asia Pacific and Middle East              757           684         2,719        3,232
   Other International                        (2 )         492            26          456
   Corporate and Other                      (234 )        (254)         (569 )       (827)

   Income from continuing operations   $   2,439         1,740         6,529        5,639

Earnings for ConocoPhillips increased 40 percent in the third quarter of 2013, while earnings for the nine-month period ended September 30, 2013, increased 16 percent. The improvements in the third quarter of 2013 primarily resulted from:

Higher gains from asset sales. Gains realized in the third quarter of 2013 were $777 million after-tax, compared with gains of $336 million after-tax in the third quarter of 2012.

Higher commodity prices.

A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.

The absence of $170 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in 2012.


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These items were partially offset by:

Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes in the Lower 48.

Higher operating expenses, mainly due to a $116 million after-tax charge related to a pending settlement in the Asia Pacific and Middle East segment, as well as increased production volumes and activity in the Lower 48 and the Asia Pacific region.

The increase in earnings in the nine-month period of 2013 was primarily due to:

Lower impairments. Non-cash impairments for the nine-month period of 2013 totaled $20 million after-tax, compared with $550 million after-tax in the nine-month period of 2012.

A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.

Higher natural gas prices.

Lower production taxes, primarily as a result of lower production volumes and prices and higher capital spending in Alaska.

The favorable resolution of pending claims and settlements of $234 million after-tax.

Absence of the 2012 U.K. tax increase of $170 million and separation costs of $80 million after-tax.

These items were partially offset by:

Higher DD&A expenses, mainly due to higher volumes in the Lower 48 and China.

Lower gains from asset sales. Gains realized in the nine-month period of 2013 were $1,118 million after-tax, compared with gains of $1,557 million after-tax in the nine-month period of 2012.

Lower crude oil, natural gas liquids and LNG prices.

Higher operating expenses, which included a $116 million after-tax charge related to a pending settlement in Asia Pacific and Middle East, and higher dry hole expenses.

See the "Segment Results" section for additional information on our segment results.

Income Statement Analysis

Equity in earnings of affiliates increased 72 percent in third quarter and 9 percent in the nine-month period of 2013. The increases primarily resulted from:

Higher earnings from FCCL Partnership, mainly as a result of higher bitumen prices and volumes.

Higher earnings from Qatar Liquefied Gas Company Limited (3) (QG3), largely due to higher LNG volumes.

Gain on dispositions increased $951 million in the third quarter and decreased $419 million in the nine-month period of 2013. Gains realized in the third quarter of 2013 primarily resulted from the disposition of our Clyden undeveloped oil sands leasehold and the disposition of our 39 percent equity interest in Phoenix Park. Gains realized in the third quarter of 2012 mostly resulted from the disposition of our equity investment in Naryanmarneftegaz (NMNG), partly offset by the loss on further dilution of our equity interest in Australia Pacific LNG (APLNG) from 42.5 percent to 37.5 percent.

Additional gains realized in the nine-month period of 2013 mainly resulted from the disposition of our interest in the Interconnector Pipeline, partly offset by a loss on the disposition of certain properties located in the Cedar Creek Anticline. Gains in the nine-month period of 2012 also included the $937 million gain on sale of our Vietnam business and the gain on sale of the Statfjord and Alba fields located in the North Sea.

Other income increased 89 percent in the nine-month period of 2013, largely as a result of a $150 million insurance settlement associated with the Bohai Bay seepage incidents.


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Purchased commodities decreased 10 percent in the third quarter and 6 percent in the nine-month period of 2013, largely as a result of lower purchased natural gas volumes, partly offset by higher natural gas prices.

Production and operating expenses increased 20 percent in the third quarter and 6 percent in the nine-month period of 2013, primarily as a result of increased drilling activity and production volumes, mostly in the Lower 48, in addition to a charge related to a pending settlement in Asia Pacific and Middle East.

Selling, general and administrative expenses decreased 24 percent in the third quarter and 32 percent in the nine-month period of 2013, mainly due to lower pension settlement expense. The nine-month period of 2013 also benefitted from the absence of separation costs, as well as lower costs related to compensation and benefit plans. For additional information, see Note 19-Employee Benefit Plans, in the Notes to Consolidated Financial Statements.

Exploration expensesincreased 46 percent in the third quarter and decreased 21 percent in the nine-month period of 2013. Both periods of 2013 were impacted by higher dry hole costs. The nine-month period of 2012 also included the $481 million impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project.

DD&A increased 15 percent in both the third quarter and nine-month period of 2013. The increase was mostly associated with higher production volumes in the Lower 48. In addition, higher production volumes in China contributed to the increase in the nine-month period of 2013.

Impairments decreased 90 percent in the nine-month period of 2013. The nine-month period of 2012 included a $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project, in addition to an increase in the asset retirement obligation for the U.K. Don Field, which has ceased production. For additional information, see Note 9-Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 18 percent in the nine-month period of 2013, mainly as a result of lower production taxes due to lower crude oil production volumes and prices and higher capital spending in Alaska.

Interest and debt expense decreased 23 percent in the nine-month period of 2013, primarily due to lower interest expense from lower average debt levels and higher capitalized interest on projects.

See Note 22-Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.


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Summary Operating Statistics



                                                    Three Months Ended          Nine Months Ended
                                                       September 30                September 30
                                                        2013        2012          2013         2012

Average Net Production
Crude oil (MBD)*                                         552          553          587          587
Natural gas liquids (MBD)                                156          151          158          155
Bitumen (MBD)                                            107           92          105           88
Natural gas (MMCFD)**                                  3,930        4,037        3,963        4,100


Total Production (MBOED)                               1,470        1,470        1,511        1,514


                                                                   Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)                            $   106.60       102.54       104.20       106.66
Natural gas liquids (per barrel)                       41.14        41.08        40.64        46.84
Bitumen (per barrel)                                   76.06        56.86        57.08        56.23
Natural gas (per thousand cubic feet)                   5.99         5.28         6.14         5.38


                                                                 Millions of Dollars
Exploration Expenses
General administrative; geological and
geophysical; and lease rentals                    $      180          146          566          452
Leasehold impairment                                      32           63          142          627
Dry holes                                                101            6          203           76

                                                  $      313          215          911        1,155

Excludes discontinued operations.

*Thousands of barrels per day.

**Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2013, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

Total production from continuing operations remained flat in both the third quarter and nine-month period of 2013, compared with the corresponding periods of 2012, while average liquids production increased 2 percent over the same periods. Production increased in both periods of 2013 due to new production from major developments, mainly from the Lower 48, Christina Lake in Canada, and Malaysia; higher production in China; and increased drilling programs, mostly in western Canada, the Lower 48 and Norway. However, these increases were offset by normal field decline, the impact of the disruption in Libya, due to the closure of the Es Sider crude oil export terminal, and asset dispositions. Excluding dispositions, downtime and the impact from the closure of the Es Sider Terminal in Libya, production grew by 29 MBOED, or 2 percent, compared with the third quarter of 2012, and 51 MBOED, or 3 percent, compared with the nine-month period of 2012.


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Segment Results

Alaska



                                                            Three Months Ended          Nine Months Ended
                                                               September 30                September 30
                                                               2013         2012          2013         2012


Income From Continuing Operations (millions of dollars)   $     494          535         1,719        1,706


Average Net Production
Crude oil (MBD)                                                 161          157           176          185
Natural gas liquids (MBD)                                        11           10            15           15
Natural gas (MMCFD)                                              35           51            43           55


Total Production (MBOED)                                        178          176           198          209


Average Sales Prices
Crude oil (dollars per barrel)                            $  110.95       106.53        109.14       110.54
Natural gas (dollars per thousand cubic feet)                  4.09         3.97          4.56         4.21

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of September 30, 2013, Alaska contributed 22 percent of our worldwide liquids production and 1 percent of our natural gas production.

Alaska's earnings decreased 8 percent in the third quarter and increased 1 percent in the nine-month period of 2013, compared with the same periods of 2012. The decrease in earnings in the third quarter of 2013 was mostly due to lower crude oil sales volumes, partly offset by higher crude oil prices and . . .

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