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COP > SEC Filings for COP > Form 10-Q on 2-Aug-2013All Recent SEC Filings

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Form 10-Q for CONOCOPHILLIPS


2-Aug-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 51.

Due to the separation of our downstream businesses in 2012 and our intention to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Nigerian and Algerian businesses, which are 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 30 countries. At June 30, 2013, we had approximately 17,500 employees worldwide and total assets of $117 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, yet with a more 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 Europe, Asia and Australia; several major international developments; and an emerging 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 second quarter of 2013, we achieved production of 1,552 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 42 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 June 2013, we generated $8.3 billion in cash from continuing operations, paid dividends on our common stock of $1.6 billion, funded a $7.5 billion capital program and continued to progress the asset disposition program.

During the first six months of 2013, we received proceeds from dispositions of approximately $1.7 billion, which mainly resulted from:

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.

The previously announced sales of Kashagan, Nigeria and Algeria are anticipated to close in 2013 and generate approximately $9.0 billion in expected 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 $15.9 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 will fund a portion of our capital program with the proceeds from strategic 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 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           Six Months Ended
                                                           June 30                    June 30

                                                         2013         2012         2013         2012

Market Indicators
WTI (per barrel)                                   $    94.12        93.44        94.21        98.21
Dated Brent (per barrel)                               102.44       108.19       107.50       113.34
U.S. Henry Hub first of month (per million
British thermal units)                                   4.10         2.21         3.72         2.47

Industry crude prices for WTI remained relatively flat in the second quarter of 2013, compared with the same period in 2012, while Brent prices decreased 5 percent in the second quarter of 2013. Global oil prices weakened during the second quarter of 2013, mainly as a result of slowing global economic growth and increasing North American oil supply. The WTI-Brent differential has decreased considerably during 2013, as additional infrastructure helped to alleviate the bottleneck at Cushing, Oklahoma, and as U.S. refineries utilized more domestic light sweet barrels instead of foreign light sweet imports.

Henry Hub natural gas prices increased 86 percent in the second quarter of 2013, compared with the same period in 2012. The increase was due to a colder winter in 2013 compared with 2012, which increased demand and reduced natural gas storage inventories to below the normal inventory levels going into the summer cooling season.

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 15 percent in the second quarter of 2013, compared with the same period of 2012. Bitumen prices strengthened during the second 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 $55.69 per barrel in the second quarter of 2013, compared with $39.23 per barrel in the first quarter of 2013 and $51.38 per barrel in the second quarter of 2012.

Key Operating and Financial Highlights

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

Strong second-quarter production performance; raising full-year production guidance.

Second-quarter production of 1,552 MBOED, including continuing operations of 1,510 MBOED and discontinued operations of 42 MBOED.

Major turnarounds and tie-in activity on plan.

Eagle Ford production of 121 MBOED, up 98 percent compared with second-quarter 2012.

Christina Lake Phase E startup in July; four additional major projects on track for startup by year end in the North Sea and Malaysia.

Exploration momentum continues with drilling in the Gulf of Mexico, Australia's Browse Basin, and unconventional plays in Canada and the Lower 48.

Increased quarterly dividend by 4.5 percent.

Outlook

Third quarter 2013 production from continuing operations is expected to be 1,460 to 1,490 MBOED, reflecting previously announced planned downtime and turnaround activity. Full-year 2013 production from continuing operations is expected to be 1,515 to 1,530 MBOED. Full-year 2013 production from discontinued operations is expected to be 25 to 40 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. 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 six-month periods ended June 30, 2013, is based on a comparison with the corresponding period of 2012.

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

                                                                 Millions of Dollars

                                                Three Months Ended                Six Months Ended
                                                      June 30                          June 30

                                                    2013           2012              2013           2012


Alaska                                      $        682            551             1,225          1,171
Lower 48 and Latin America                           247            119               380            374
Canada                                                 5            (94)              138           (643)
Europe                                               261            669               692          1,058
Asia Pacific and Middle East                       1,030            794             1,962          2,548
Other International                                   14            (57)               28            (36)
Corporate and Other                                 (173)          (262)             (335)          (573)

Income from continuing operations           $      2,066          1,720             4,090          3,899

Earnings for ConocoPhillips increased 20 percent in the second quarter of 2013, while earnings for the six-month period ended June 30, 2013, increased 5 percent. The improvements in the second quarter and six-month period of 2013 primarily resulted from:

Higher volumes, a continued portfolio shift to liquids and a higher proportion of production in high-margin areas.

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

Higher natural gas prices.

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

These items were partially offset by:

Lower gains from asset sales. Gains realized in the second quarter of 2013 were $71 million after-tax, compared with gains of $281 million after-tax in the second quarter of 2012. Gains realized in the six-month period of 2013 were $341 million after-tax, compared with gains of $1,220 million after-tax in the six-month period of 2012.


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Lower crude oil, natural gas liquids and LNG prices.

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

In addition, earnings in the six-month period of 2013 benefitted from lower impairments. Non-cash impairments in the six-month period of 2013 totaled $20 million after-tax, compared with impairments in the six-month period of 2012 of $550 million after-tax. Lower bitumen prices partially offset the increase in earnings in the six-month period of 2013.

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

Income Statement Analysis

Equity in earnings of affiliates decreased 16 percent in the six-month period of 2013. The decrease primarily resulted from:

Lower earnings from Qatar Liquefied Gas Company Limited (3) (QG3), largely due to the absence of a $72 million tax-related adjustment recorded in 2012 and lower prices, partly offset by higher volumes.

Lower earnings from FCCL Partnership, mainly as a result of lower bitumen prices and higher operating expenses, partly offset by higher bitumen volumes.

Lower earnings from Lane Energy Poland Sp.z o.o., primarily due to expenses related to a mechanical dry hole.

Gain on dispositions decreased 84 percent in the second quarter and 90 percent in the six-month period of 2013. Gains realized in the second quarter of 2013 primarily resulted from the disposition of certain properties located in southwest Louisiana, compared with gains realized in the second quarter of 2012, which mostly resulted from the disposition of our Statfjord and Alba fields located in the North Sea. Additional gains realized in the six-month period of 2013 mainly resulted from the disposition of our interest in the Interconnector Pipeline in Europe, partly offset by a loss on the disposition of certain properties located in the Cedar Creek Anticline in the Lower 48 in 2013. The first quarter of 2012 also included the $937 million gain on sale of our Vietnam business.

Other income increased $137 million in the second quarter and $142 million in the six-month period of 2013, largely as a result of an insurance settlement associated with the Bohai Bay seepage incidents.

Production and operating expenses decreased 7 percent in the second quarter of 2013, primarily as a result of the reduction of an accrual related to the Federal Energy Regulatory Commission (FERC) approval of cost allocation (pooling) agreements with the remaining owners of the Trans-Alaska Pipeline System (TAPS).

Selling, general and administrative expenses decreased 36 percent in the six-month period of 2013, mainly as a result of lower costs related to compensation and benefit plans and the absence of costs associated with the separation of Phillips 66.

Exploration expenses decreased 36 percent in the six-month period of 2013, largely due to lower leasehold impairment costs, partly offset by higher dry hole costs. The six-month period of 2012 included the impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project.

DD&A increased 16 percent in the second quarter and 15 percent in the six-month period of 2013. The increase was mostly associated with higher production volumes in the Lower 48 and China.

Impairments decreased 90 percent in the six-month period of 2013. The six-month period of 2012 included a $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project,


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in addition to an increase in the asset retirement obligation for the Don Field in the United Kingdom, which has ceased production. For additional information, see Note 9-Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 29 percent in the second quarter and 23 percent in the six-month period of 2013, mainly as a result of lower production taxes due to lower crude oil production volumes and prices in Alaska.

Interest and debt expense for the second quarter and six-month period of 2013 decreased 29 and 30 percent, respectively, 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                 Six Months Ended
                                                         June 30                           June 30

                                                      2013            2012              2013            2012

Average Net Production
Crude oil (MBD)*                                       585             585               605             604
Natural gas liquids (MBD)                              158             150               159             156
Bitumen (MBD)                                          100              88               104              86
Natural gas (MMCFD)**                                3,998           4,000             3,980           4,130


Total Production (MBOED)                             1,510           1,489             1,531           1,535


                                                                     Dollars Per Unit

Average Sales Prices
Crude oil (per barrel)                        $     100.07          105.43            103.06          108.65
Natural gas liquids (per barrel)                     37.80           44.36             40.39           49.78
Bitumen (per barrel)                                 55.69           51.38             47.04           55.89
Natural gas (per thousand cubic feet)                 5.86            5.25              5.85            5.43


                                                                    Millions of Dollars

Exploration Expenses
General administrative; geological and
geophysical; and lease rentals                $        145             149               386             306
Leasehold impairment                                    78              52               110             564
Dry holes                                               98              64               102              70

                                              $        321             265               598             940

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 June 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 increased 1 percent in the second quarter of 2013 and remained relatively flat in the six-month period of 2013, while average liquids production increased 2 percent and 3 percent over the corresponding periods in 2012. In both periods of 2013, production increased due to new production from major developments, mainly from shale plays in the Lower 48 and the ramp-up of production from new phases at FCCL and Malaysia; higher production in China; and increased drilling programs, mostly in western Canada, the Lower 48 and Norway. These increases were nearly offset by normal field decline, the impact from asset dispositions and higher planned and unplanned downtime.


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Segment Results

Alaska




                                                   Three Months Ended                 Six Months Ended
                                                         June 30                           June 30

                                                      2013            2012              2013            2012


Income From Continuing Operations (millions
of dollars)                                   $        682             551             1,225           1,171


Average Net Production
Crude oil (MBD)                                        176             190               183             199
Natural gas liquids (MBD)                               15              16                16              17
Natural gas (MMCFD)                                     38              56                47              57


Total Production (MBOED)                               197             215               207             226


Average Sales Prices
Crude oil (dollars per barrel)                $     106.09          112.38            108.35          112.28
Natural gas (dollars per thousand cubic
feet)                                                 4.03            3.93              4.73            4.31

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of June 30, 2013, Alaska contributed 23 percent of our worldwide liquids production and 1 percent of our natural gas production.

Alaska's earnings increased 24 percent in the second quarter and 5 percent in the six-month period of 2013, compared with the same periods of 2012. Earnings in both periods of 2013 benefitted from lower production taxes, mainly as a result of lower prices, higher 2013 capital spending and lower crude oil production volumes, as well as the impact of a recent ruling by FERC, as more fully described below. These increases to earnings were partly offset by lower volumes and lower crude oil prices.

In 2012, the major owners of TAPS filed a proposed settlement with FERC to resolve pooling disputes prior to August 2012 and establish a voluntary pooling agreement to pool costs prospectively from August 2012. In July 2013, the FERC approved the proposed settlement and pooling agreement without modification. Under the terms of the agreements, we agreed to pay the other remaining owners of TAPS approximately $356 million, including interest. We expect to pay this amount in the third quarter of 2013. As a result of FERC approval of these agreements, we reduced a related accrual in the second quarter of 2013, which decreased our production and operating expenses by $97 million after-tax.

Average production decreased 8 percent in both the second quarter and six-month period of 2013. The reduction in both periods of 2013 was mostly due to normal field decline.

Chukchi Sea

In April 2013, we announced our 2014 Chukchi Sea exploration drilling plans are on hold given the uncertainties of evolving federal regulatory requirements and operational permitting standards. Once these requirements are clarified and better defined, we will re-evaluate our Chukchi Sea drilling plans.


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Lower 48 and Latin America




                                                   Three Months Ended                 Six Months Ended
                                                         June 30                           June 30
. . .
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